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Report Title “Integrated Geologic-Engineering Model for Reef and Carbonate Shoal Reservoirs Associated with Paleohighs: Upper Jurassic Smackover Formation, Northeastern Gulf of Mexico” Type of Report Technical Progress Report for Year 2 Reporting Period Start Date September 1, 2001 Reporting Period End Date August 31, 2002 Principal Author Ernest A. Mancini (205/348-4319) Department of Geological Sciences Box 870338 202 Bevill Building University of Alabama Tuscaloosa, AL 35487-0338 Date Report was Issued September 25, 2002 DOE Award Number DE-FC26-00BC15303 Name and Address of Participants

Ernest A. Mancini Dept. of Geological Sciences Box 870338 Tuscaloosa, AL 35487-0338

Bruce S. Hart Earth & Planetary Sciences McGill University 3450 University St. Montreal, Quebec H3A 2A7 CANADA

Thomas Blasingame Dept. of Petroleum Engineering Texas A&M University College Station, TX 77843-3116

Robert D. Schneeflock, Jr. Paramount Petroleum Co., Inc. 230 Christopher Cove Ridgeland, MS 39157

Richard K. Strahan Strago Petroleum Corporation 811 Dallas St., Suite 1407 Houston, TX 77002

Roger M. Chapman Longleaf Energy Group, Inc. 319 Belleville Ave. Brewton, AL 36427

Disclaimer This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.

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ABSTRACT

The University of Alabama in cooperation with Texas A&M University, McGill University,

Longleaf Energy Group, Strago Petroleum Corporation, and Paramount Petroleum Company are

undertaking an integrated, interdisciplinary geoscientific and engineering research project. The

project is designed to characterize and model reservoir architecture, pore systems and rock-fluid

interactions at the pore to field scale in Upper Jurassic Smackover reef and carbonate shoal

reservoirs associated with varying degrees of relief on pre-Mesozoic basement paleohighs in the

northeastern Gulf of Mexico. The project effort includes the prediction of fluid flow in carbonate

reservoirs through reservoir simulation modeling which utilizes geologic reservoir

characterization and modeling and the prediction of carbonate reservoir architecture,

heterogeneity and quality through seismic imaging.

The primary objective of the project is to increase the profitability, producibility and

efficiency of recovery of oil from existing and undiscovered Upper Jurassic fields characterized

by reef and carbonate shoals associated with pre-Mesozoic basement paleohighs.

The principal research effort for Year 2 of the project has been reservoir characterization,

3-D modeling and technology transfer. This effort has included six tasks: 1) the study of rock-

fluid interactions, 2) petrophysical and engineering characterization, 3) data integration, 4) 3-D

geologic modeling, 5) 3-D reservoir simulation and 6) technology transfer. This work was

scheduled for completion in Year 2.

Overall, the project work is on schedule. Geoscientific reservoir characterization is

essentially completed. The architecture, porosity types and heterogeneity of the reef and shoal

reservoirs at Appleton and Vocation Fields have been characterized using geological and

geophysical data. The study of rock-fluid interactions is near completion. Observations regarding

iii

the diagenetic processes influencing pore system development and heterogeneity in these reef

and shoal reservoirs have been made. Petrophysical and engineering property characterization

has been essentially completed. Porosity and permeability data at Appleton and Vocation Fields

have been analyzed, and well performance analysis has been conducted. Data integration is up to

date, in that, the geological, geophysical, petrophysical and engineering data collected to date for

Appleton and Vocation Fields have been compiled into a fieldwide digital database. 3-D

geologic modeling of the structures and reservoirs at Appleton and Vocation Fields has been

completed. The model represents an integration of geological, petrophysical and seismic data.

3-D reservoir simulation of the reservoirs at Appleton and Vocation Fields has been completed.

The 3-D geologic model served as the framework for the simulations. A technology workshop

on reservoir characterization and modeling at Appleton and Vocation Fields was conducted to

transfer the results of the project to the petroleum industry.

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Table of Contents

Page

Title Page ............................................................................................................................ i Disclaimer .......................................................................................................................... i Abstract .............................................................................................................................. ii Table of Contents ............................................................................................................... iv Introduction ........................................................................................................................ 1 Executive Summary ........................................................................................................... 9 Experimental ...................................................................................................................... 12 Work Accomplished in Year 2 ..................................................................................... 12 Work Planned for Year 3 .............................................................................................. 183 Results and Discussion ....................................................................................................... 203 Geoscientific Reservoir Characterization...................................................................... 203 Rock-Fluid Interactions ................................................................................................ 210 Petrophysical and Engineering Property Characterization ........................................... 218 3-D Geologic Modeling ................................................................................................ 219 3-D Reservoir Simulation Model .................................................................................. 222 Data Integration ............................................................................................................ 223 Conclusions ........................................................................................................................ 223 References .......................................................................................................................... 226

INTRODUCTION


Longleaf Energy Group, Strago Petroleum Corporation, and Paramount Petroleum Company is






reservoirs through reservoir simulation modeling that utilizes geologic reservoir characterization

and modeling and the prediction of carbonate reservoir architecture, heterogeneity and quality

through seismic imaging.

The Upper Jurassic Smackover Formation (Figure 1) is one of the most productive

hydrocarbon reservoirs in the northeastern Gulf of Mexico. Production from Smackover

carbonates totals 1 billion barrels of oil and 4 trillion cubic feet of natural gas. The production is

from three plays: 1) basement ridge play, 2) regional peripheral fault play, and 3) salt anticline

play (Figure 2). Unfortunately, much of the oil in the Smackover fields in these plays remains

unrecovered because of a poor understanding of the rock and fluid characteristics that affects our

understanding of reservoir architecture, heterogeneity, quality, fluid flow and producibility. This

scenario is compounded because of inadequate techniques for reservoir detection and the

characterization of rock-fluid interactions, as well as imperfect models for fluid flow prediction.

This poor understanding is particularly illustrated for the case with Smackover fields in the

basement ridge play (Figure 3) where independent producers dominate the development and

management of these fields. These producers do not have the financial resources and/or staff

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expertise to substantially improve the understanding of the geoscientific and engineering factors

affecting the producibility of Smackover carbonate reservoirs, which makes research and

application of new technologies for reef-shoal reservoirs all that more important and urgent. The

research results from studying the fields identified for this project will be of direct benefit to

these producers.

This interdisciplinary project is a 3-year effort to characterize, model and simulate fluid

flow in carbonate reservoirs and consists of 3 phases and 11 tasks. Phase 1 (1 year) of the project

involves geoscientific reservoir characterization, rock-fluid interactions, petrophysical and

engineering property characterization, and data integration. Phase 2 (1.5 years) includes geologic

modeling and reservoir simulation. Phase 3 (0.5 year) involves building the geologic-engineering

model, testing the geologic-engineering model, and applying the geologic-engineering model.

The principal goal of this project is to assist independent producers in increasing oil

producibility from reef and shoal reservoirs associated with pre-Mesozoic paleotopographic

features through an interdisciplinary geoscientific and engineering characterization and modeling

of carbonate reservoir architecture, heterogeneity, quality and fluid flow from the pore to field

scale.

The objectives of the project are as follows:

1. Evaluate the geological, geophysical, petrophysical and engineering properties of reef-shoal

reservoirs and their associated fluids, in particular, the Appleton (Figure 4) and Vocation

(Figure 5) Fields.

2. Construct a digital database of integrated geoscience and engineering data taken from reef-

shoal carbonate reservoirs associated with basement paleohighs.

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3. Develop a geologic-engineering model(s) for improving reservoir detection, reservoir

characterization, flow-space imaging, flow simulation, and performance prediction for reef-

shoal carbonate reservoirs based on a systematic study of Appleton and Vocation Fields.

4. Validate and apply the geologic-engineering model(s) on a prospective Smackover reservoir

through an iterative interdisciplinary approach, where adjustments of properties and

concepts will be made to improve the model(s).

This project has direct and significant economic benefits because the Smackover is a prolific

hydrocarbon reservoir in the northeastern Gulf of Mexico. Smackover reefs represent an

underdeveloped reservoir, and the basement ridge play in which these reefs are associated

represents an underexplored play, Initial estimations indicate the original oil resource target

available in this play from the 40 fields that have been discovered and developed approximates

at least 160 million barrels. Any newly discovered fields are expected to have an average of 4

million barrels of oil. The combined estimated reserves of the Smackover fields (Appleton and

Vocation Fields) proposed for study in this project total 9 million barrels of oil. Successful

completion of the project should lead to increased oil producibility from Appleton and Vocation

Fields and from Smackover reservoirs in general. Production of these domestic resources will

serve to reduce U.S. dependence on foreign oil supplies.

Completion of the project will contribute significantly to the understanding of: the geologic

factors controlling reef and shoal development on paleohighs, carbonate reservoir architecture

and heterogeneity at the pore to field scale, generalized rock-fluid interactions and alterations in

carbonate reservoirs, the geological and geophysical attributes important to geologic modeling of

reef-shoal carbonate reservoirs, the critical factors affecting fluid flow in carbonate reservoirs,

particularly with regard to reservoir simulation and the analysis of well performance, the

9

elements important to the development of a carbonate geologic-engineering model, and the

geological, geophysical, and/or petrophysical properties important to improved carbonate

reservoir detection, characterization, imaging and flow prediction.

EXECUTIVE SUMMARY














The principal research effort for Year 2 of the project has been reservoir description and

characterization. This effort has included four tasks: 1) geoscientific reservoir characterization,

2) the study of rock-fluid interactions, 3) petrophysical and engineering characterization and 4)

data integration.

Geoscientific reservoir characterization is essentially completed. The architecture, porosity

types and heterogeneity of the reef and shoal reservoirs at Appleton and Vocation Fields have

10

been characterized using geological and geophysical data. All available whole cores have been

described and thin sections from these cores have been studied. Depositional facies were

determined from the core descriptions and well logs. The thin sections studied represent the

depositional facies identified. The core data and well log signatures have been integrated and

calibrated on graphic logs. The well log and seismic data have been tied through the generation

of synthetic seismograms. The well log, core, and seismic data have been entered into a digital

database. Structural maps on top of the basement, reef, and Smackover/Buckner have been

constructed. An isopach map of the Smackover interval has been prepared, and thickness maps

of the Smackover facies have been prepared. Cross sections have been constructed to illustrate

facies changes across these fields. Maps have been prepared using the 3-D seismic data that

Longleaf and Strago contributed to the project to illustrate the structural configuration of the

basement surface, the reef surface, and Buckner/Smackover surface. Seismic forward modeling

and attribute-based characterization has been completed for Appleton Field. Petrographic

analysis has been completed and a paragenetic sequence for the Smackover in these fields has

been prepared.

The study of rock-fluid interactions is near completion. Thin sections (379) have been

studied from 11 cores from Appleton Field to determine the impact of cementation, compaction,

dolomitization, dissolution and neomorphism has had on the reef and shoal reservoirs in this

field. Thin sections (237) have been studied from 11 cores from Vocation Field to determine the

paragenetic sequence for the reservoir lithologies in this field. An additional 73 thin sections

have been prepared for the shoal and reef lithofacies in Vocation Field to identify the diagenetic

processes that played a significant role in the development of the pore systems in the reservoirs

at Vocation Field. The petrographic analysis and pore system studies essentially have been

11

completed. A paragenetic sequence for the Smackover carbonates at Appleton and Vocation

Fields has been prepared. Pore systems studies continue.

Petrophysical and engineering property characterization is essentially completed.

Petrophysical and engineering property data have been gathered and tabulated for Appleton and

Vocation Fields. These data include oil, gas and water production, fluid property (PVT) analyses

and porosity and permeability information. Porosity and permeability characteristics of

Smackover facies have been analyzed for each well using porosity histograms, permeability

histograms and porosity versus depth plots. Log porosity versus core porosity and porosity

versus permeability cross plots for wells in the fields have been prepared.

Well performance studies through type curve and decline curve analyses have been

completed for the wells in Appleton and Vocation Fields, and the original oil in place and

recoverable oil remaining for the fields has been calculated.

3-D geologic modeling of the structure and reservoirs at Appleton and Vocation Fields has

been completed. The model represents an integration of geological, petrophysical and seismic

data.

3-D reservoir simulations of the reservoirs at Appleton and Vocation Fields have been

completed. The 3-D geologic model served as the framework for these simulations. The

acquisition of additional pressure data would improve the simulation models.

Data integration is up to date, in that, geological, geophysical, petrophysical and engineering

data collected to date for Appleton and Vocation Fields have been compiled into a fieldwide

digital database for development of the geologic-engineering model for the reef and carbonate

shoal reservoirs for each of these fields.

12

A technology workshop on reservoir characterization and modeling at Appleton and

Vocation Fields was conducted to transfer the results of the project to the petroleum industry.

EXPERIMENTAL

The principal research effort for Year 2 of the project has been reservoir characterization,

including the study of rock-fluid interactions, petrophysical and engineering characterization and

data integration; 3-D modeling, including 3-D geologic modeling and 3-D reservoir simulation;

and technology transfer (Table 1).

Table 1. Milestone Chart.

Project Year/Quarter Tasks 2000 2001 2002 2003

3 4 1 2 3 4 1 2 3 4 1 2 Reservoir Characterization (Phase 1) Task 1—Geoscientific Reservoir Characterization xxxxxx xxx Task 2—Rock-Fluid Interactions xxxxxx xxx Task 3—Petrophysical Engineering Characterization xxxxxx xxx Task 4—Data Integration xxx 3-D Modeling (Phase 2) Task 5—3-D Geologic Model xxxxxx Task 6—3-D Reservoir Simulation Model xxxxxx Task 7—Geologic-Engineering Model xxxxxx Testing and Applying Model (Phase 3) Task 8—Testing Geologic-Engineering Model xxxxxxTask 9—Applying Geologic-Engineering Model xxxxxxTechnological Transfer Task 10—Workshops xx xxTechnical Reports Task 11—Quarterly, Topical and Annual Reports x x x x x x x x x x x

xxxxx Work Planned Work Accomplished in Year 2

Reservoir Description and Characterization (Phase 1)

Task 1—Geoscientific Reservoir Characterization.--This task will characterize reservoir

architecture, pore systems and heterogeneity based on geological and geophysical properties.

This work will be done for all well logs, cores, seismic data and other data for Vocation Field

and will be done for Appleton Field by integrating the new data obtained from drilling the

13

sidetrack well in Appleton Field and the data available from five additional cores and 3-D

seismic in the field area. The first phase of the task includes core descriptions, including

lithologies, sedimentary structures, lithofacies, depositional environments, systems tracts, and

depositional sequences. Graphic logs constructed from the core studies will depict the

information described above. Core samples will be selected for petrographic, XRD, SEM, and

microprobe analyses. The graphic logs will be compared to available core analysis and well log

data. The core features and core analyses will be calibrated to the well log patterns. A numerical

code system will be established so that these data can be entered into the digital database for

comparison with the core analysis data and well log measurements and used in the reservoir

modeling. The next phase is the link between core and well log analysis and reservoir modeling.

It involves the preparation of stratigraphic and structural cross sections to illustrate structural

growth, lithofacies and reservoir geometry, and depositional systems tract distribution. Maps will

be prepared to illustrate lithofacies distribution, stratigraphic and reservoir interval thickness

(isolith and isopach maps), and stratal structural configurations. These cross sections and maps,

in association with the core descriptions, will be utilized to make sequence stratigraphic,

environment of deposition, and structural interpretations. Standard industry software, such as

StratWorks and Z-Map, will be used in the preparation of the cross sections and subsurface

maps. The third phase will encompass the interpreting of seismic data and performing

stratigraphic and structural analyses. Seismic interpretations will be guided by the generation of

synthetic seismograms resulting from the tying of well log and seismic data and by the

comparison of seismic transects with geologic cross sections. Seismic forward modeling and

attribute-based characterization will be performed. Structure and isopach maps constructed from

well logs will be refined utilizing the seismic data. The seismic imaging of the structure and

14

stratigraphy, forward modeling and attribute characterization will be accomplished utilizing

standard industry software, such as 2d/3d PAK, Earthwave and SeisWorks. The next phase

includes identification and quantification of carbonate mineralogy and textures (grain, matrix

and cement types), pore topology and geometry, and percent of porosity and is performed to

support and enhance the visual core descriptions. These petrographic, XRD, SEM and

microprobe analyses will confirm and quantify the observations made in the core descriptions.

This analysis provides the opportunity to study reservoir architecture and heterogeneity at the

microscopic scale. The fifth phase involves study of pore systems in the reservoir, including pore

types and throats through SEM analysis. This phase will examine pore shape and geometry and

the nature and distribution of pore throats to determine the features of the pore systems that are

affecting reservoir producibility.

Appleton Field. All available whole cores (11) from Appleton Field have been described

and thin sections (379) from these cores have been studied. Graphic logs were constructed

describing each of the cores (Figures 6 through 16). Depositional facies were determined from

the core descriptions. From the study of thin sections, the petrographic characteristics of these

lithofacies have been described, and the pore systems inherent to these facies have been

identified (Table 2). The core data and well log signatures have been integrated and calibrated on

these graphic logs.

For Appleton Field (Figure 4), the well log and core data have been entered into a digital

database and structural maps on top of the basement (Figure 17), reef (Figure 18), and

Smackover/Buckner (Figure 19) have been constructed. An isopach map of the Smackover

interval has been prepared (Figure 20), and thickness maps of the sabkha facies (Figure 21), tidal

flat facies (Figure 22), shoal complex (Figure 23), tidal flat/shoal complex (Figure 24) and reef

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Brian Panetta

21

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Brian Panetta

24

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Brian Panetta

25

T able 2. Characteristics of Smackover Lithofacies in the Appleton Field Area.

Lithofacies Lithology Allochems Pore Types Porosity Permeability

Carbonate mudstone Dolostone andanhydritic dolostone

None Intercrystalline Low(1.2 to 2.5%)

Low( 0.01 md)

Peloidal wackestone Dolostone tocalcareous dolostone

Peloids, ooids,intraclasts

Intercrystalline,moldic

Low to moderate(2.6 to 12.4%)

Low( 0.01 to 0.11 md)

Peloidal packstone Dolomitic limestone Peloids, ooids,oncoids,intraclasts

Interparticulate,moldic,intercrystalline


Low to moderate( 0.01 to 0.51 md)

Peloidal/oncoidalpackstone

Dolostone tocalcareous dolostone

Peloids, oncoids,intraclasts

Interparticulate Low(1.2 to 6.1%)

Low( 0.01 md)

Peloidal/ooliticpackstone

Dolostone Peloids, ooids,skeletal grains,intraclasts

Moldic,intercrystalline,interparticulate

Low(1.3 to 4.5%)

Low( 0.01 md)

Peloidal grainstone Calcareous dolostone Peloids, oncoids,algal grains,intraclasts

Interparticulate,fenestral, moldic,interparticulate,vuggy

Low to high(1.0 to 19.9%)

Low to high( 0.01 to 722 md)

Oncoidal grainstone Calcareous dolostoneto dolostone

Oncoids, peloids,intraclasts

Interparticulate,intraparticulate,fenestral


Low to high( 0.01 to 8.27 md)

Oolitic grainstone Dolostone tolimestone

Ooids, peloids,oncoids,intraclasts

Interparticulate,moldic,intercrystalline

Moderate to high(8.3 to 20.7%)

Moderate to high(3.09 to 406 md)

Oncoidal/peloidal/oolitic grainstone

Dolostone tocalcareous dolostone

Oncoids, peloids,ooids, algalgrains

Interparticulate,moldic, vuggy

Low to high(1.9 to 19%)


Algal grainstone Dolomitic limestone tocalcareous dolostone

Algal grains,oncoids,peloids, ooids

Interparticulate,moldic, vuggy,fenestral,intercrystalline

Low to high(1.7 to 23.1%)


Microbialboundstone(bafflestone)

Dolostone Algae, intraclasts,oncoids, peloids

Shelter, vuggy,interparticulate,intercrystalline

High(11.0 to 29.0%)

High(8.13 to 4106 md)

Microbial bindstone Dolostone Algae, peloids,ooids

Shelter, vuggy,fenestral, moldic,interparticulate

High(11.9 to 20.7%)

High(11 to 1545 md)

Algal laminite Dolostone todolomitic limestone

Algae, peloids,oncoids,intraclasts

Interparticulate,intercrystalline

Low(1.1 to 7.0%)

Low( 0.01 md)

Anhydrite Anhydrite None None Low( 1.0%)

Low( 0.01 md)

Brian Panetta

26

Figu

re 1

7.

Stru

ctur

e on

top

of b

asem

ent

(fro

m s

eism

ic da

ta).

By

B. J

. Pan

etta

N

Brian Panetta

27

Figu

re 1

8.

Stru

ctur

e on

top

of re

ef

(f

rom

sei

smic

data

).

B

y B.

J. P

anet

taN

Brian Panetta

28

Figu

re 1

9.

Stru

ctur

e on

top

of S

mac

kove

r/Buc

kner

(fro

m s

eism

ic da

ta).

By

B. J

. Pan

etta

N

Brian Panetta

29

Figu

re 2

0.

Isop

ach

map

of S

mac

over

inte

rval

(fro

m s

eism

ic da

ta).

By

B. J

. Pan

etta

N

Brian Panetta

30

Figu

re 2

1.

Thick

ness

map

of s

abkh

a fa

cies

(fro

m lo

g da

ta).

By

B. J

. Pan

etta

N

Brian Panetta

31

N

Figu

re 2

2.

Thick

ness

map

of t

idal

flat

facie

s

(f

rom

log

data

).

B

y B.

J. P

anet

ta

Brian Panetta

32

Figu

re 2

3.

Thick

ness

map

of s

hoal

facie

s

(f

rom

log

data

).

B

y B.

J. P

anet

taN

Brian Panetta

33

Figu

re 2

4.

Thick

ness

map

of t

idal

flat

and

sho

al fa

cies

(fro

m s

eism

ic da

ta).

By

B. J

. Pan

etta

N

Brian Panetta

34

35

complex (Figure 25) facies have been constructed. A cross section (Figure 26) illustrating the

thickness and facies changes across Appleton Field has been prepared.

The core and well log data have been integrated with the 3-D seismic data for Appleton

Field that Longleaf contributed to the project. A typical seismic profile for the field illustrating

the reef reservoir is shown in Figure 27. Figure 28 is an example of a synthetic seismogram for

the field used to tie well log and seismic data. Tables 3 and 4 and Figures 29 through 33

summarize the results of the volume-base, multi-attribute seismic study.

Vocation Field. All available whole cores (11) from Vocation Field have been described

and thin sections (237) from the cores have been studied. Graphic logs were constructed

describing each of the cores (Figures 34 through 44). Depositional facies were determined from

the core descriptions. From this work, an additional 73 thin sections are being prepared to

provide accurate representation of the lithofacies identified. From the study of thin sections, the

petrographic characteristics of these lithofacies have been described, and the pore systems

inherent to these facies have been identified (Table 5). The core data and well log signatures

have been integrated and calibrated on the graphic logs.

For Vocation Field (Figure 5), the well log and core data have been entered into a digital

database and structural maps on top of the basement (Figure 45), reef (Figure 46), and

Smackover/Buckner (Figure 47) have been constructed. An isopach of the Smackover interval

has been prepared (Figure 48) and a thickness map of the reef complex facies (Figure 49)

illustrating the thickness and facies changes across Vocation Field has been prepared. A cross

section (Figure 50) illustrating the thickness and facies changes across the field has been

constructed.

The core and well log data have been integrated with 3-D seismic data for Vocation Field

Figu

re 2

5.

Thick

ness

map

of r

eef f

acie

s

(f

rom

sei

smic

data

).

B

y B.

J. P

anet

taN

Brian Panetta

36

Sabk

a

Tida

l Fla

t

Shoa

l/Lag

oon

Reef

Base

men

t

5138

3854

6247

4835

B39

8646

33B

4991

Figu

re 2

6. C

ross

sec

tion

A - A

'.

By

B. J

. Pan

etta

.

Brian Panetta

37

38

Figure 27. Sample seismic transect showing seismic character of horizons used in the multiattribute study.

39

Figure 28. Example of Synthetic Seismogram used for well-seismic tie. Blue curve = synthetic, red = seismic trace extracted along wellbore at well location (McMillan 12-4#1). Wavelet uses to generate the synthetic shown in blue at left of image.

40

Figure 29. Time-structure map of the Buckner/Smackover seismic horizon showing principal structural features in the area of the 3-D multiattribute study. Lines show location of Figure 7a (black) and Figure 7b (red).

41

Figure 30. Cross-validation plot showing continuous decrease in average error when all wells are used (black line). The validation error (red) shows the change in average error when wells are systematically withheld from the correlation exercise. A minimum error is reached when four attributes are used, indicating that to be the optimum number of attributes. See Hampson et al. (2001) for a fuller discussion of cross-validation.

42

Figure 31. a) Top. Comparison of input density logs (black) and logs predicted using linear regression expression (red). Although the software converts the entire trace, the porosity values are strictly only valid for the stratigraphic interval being analyzed (between the two horizontal lines in each well. B) Bottom. Cross-plot of predicted versus measured density porosity using linear regression expression.

43

Figure 32. a) Top. Comparison of input density logs (black) and logs predicted using PNN (red). Although the software converts the entire trace, the porosity values are strictly only valid for the stratigraphic interval being analyzed (between the two horizontal lines in each well. B) Bottom. Cross-plot of predicted versus measured density porosity using PNN.

44

Figure 33. a) Top. NE-SW transect through porosity volume showing internal variations within the Smackover. B) Bottom. NW-SE transect through porosity volume. In both cases, porosity prediction is only valid for interval studied, between the top and base of the Smackover. See Figure 1 for location of transects.

2

4

6

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2

4

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2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

8

MD ms ws ps gs bs TS

13950'

13960'

13970'

13980'

13990'

14000'

14010'

Structures & Grain Type Porosity

anhydrite

anhydrite

anhydrite

anhydrite

iP Irregular distribution of porosity due to patchy cementation

Level rich in sulphur (13980-13981')

Carbonaceous elongated clasts, up to 0.5cm

Vugs are completely cemented

V/iP/FrA Moderate porosity, partially cementedSome very thin fractures

V/iP

Microbial buildup, Type IV and V. Oncolites up to 0.5cm in diameter are leached. The voids are lined by a white crust

M/V/Fr

Good porosity. Fractures filled with anhydrite

Oncolite level surrounded by anhydrite veins

Mudstone fragments embedded in anhydrite

Boundstone package with high porosityType IV/ V facies interbedded with Type IAbundant elongated vertical (fractures?) and horizontal (vuggy) poresAbundant pyrite

M/V/Fe

Fr?

anhydrite

Highly fractured mudstone. Fractures filled with anhydrite

x Fr

x

x Fr

x M/iP

x

x

Well Permit No. 11185STRAGO-BYRD 26-13 #2

breccia

Dep.Env.

Sa

bkh

a

Remarks

Tid

al F

lat

Ha

yne

swill

e F

orm

atio

n

Figure 34.

Core description for well permit # 11185.

By Juan Carlos Llinas.

Brian Panetta

45

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

8

2

4

6

8

2

4

6

8

2

4

6

8


13980'

13990'

14000'

14010'

14020'

14030'

14040'

14050'

14060'

14070'

14080'

14090'


no core

no core

no core

6

no core

x

x

x

x

x

x

x

M/V/iC

V/iP

M/V/iP Fractures filled with anhydrite

Microbial facies Type II.The vuggy porosity decreases upwards

M/V

M/V Interval with very high porosity (13996-14003')

Fr

Fr

There is a white rim around the vugs that reduces their size

breccia

breccia

Microbial buildup Type IV

V/iP Low porosity

Fractures filled with anhydrite

Some fractures filled with calcite. Very good porosity

Microbial reef Type I fabric. M/VFr Some fractures and vugs filled with calcite

Stromatolite and thrombolite fabric. Cavities filled with anhydrite. No porosity

Fractures filled with calcite

Small fractures filled with An/CaNo noticeable porositySome floating clasts of the same material

No noticeable porosity

A Big anhydrite nodulesMicrobial buildup,Type IM/V

Interbedding of some thin levels with thrombolite fabric No porosity due to high cementation

Reef facies with thrombolite fabric, Type I; sucrosic matrixModerate to good porosity

Some fractures filled with anhydriteM/V

Type IV microbial facies

Oil impregnated

All pores and fractures are cemented by anhydrite/calcite

x

x V Microbial reef, Type I facies

x

x

Py Fr

iP

MPy Pores are cemented

Dep.Env.

Remarks

Mic

robi

al R

eef C

ompl

exS

hallo

w L

agoo

nM

icro

bial

Bui

ldup

Tid

al F

lat

Well Permit No. 1599 B.C. QUIMBY 27-15 #1

Figure 35.

Core Description for well permit # 1599.


Brian Panetta

46

2

4

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2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8


14100'

14130'

14140'

14150'

14160'

14170'

14180'

14190'


breccia

x

x

x

x

M/V/iP

M/V/iP

Reef facies with thrombolite fabric, Type IGood porosityM/V

High porosity interval (14131-14142')

M/VVery high to moderate porosity

M/V

Anhydrite filling some fractures and voids. Good porosity

brecciaA

Anhydrite filling cavities and fractures

Reef facies with Type I fabricSucrosic matrix

Microbial facies Type II

M/V

Fr

Large elongated clasts of reef fabric in a sandy matrix

Very low porosityiP

Microbial facies Type II

Some patches with low porosity, but good porosity in general

Moderate to low porosity due to high cementationV/iP

V/iP High porosity

V/iP

Abundant elongated vugs (fractures?)

Bioturbation?

x

x

x

Microbial facies Type IIFrV

xSucrosic texture?

x Fr

Well Permit No. 1599 (cont.) B.C. QUIMBY 27-15 #1

Calcite filling cavernous porosity

Dep.Env. Remarks

Mic

robi

al R

eef C

ompl

ex

no core

Figure 35 (continued).



i

Brian Panetta

47

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

8

2

4

6

8

2

4

6

8

2

4

6

8


14130'

14140'

14150'

14160'

14170'

14180'

14250'

14260'

14270'

14280'

A


HAYNESVILLEFORMATION

anhydrite

no core

anhydrite

no core

x

x

x

xx

x

xxx

x

xx

x

xx

x

x

xx

x

xx

x

x

6

A

A

Thin layers of nodular and layered anhydrite

A

Very low porosity

A

A

Very low porosity

M/iP/VA

A

A

Very low porosityM/iP

A

Microbial texture?M/iP Good porosity

A

M/iP Moderate to good porosity

Oil?

Layered and coalesced nodular anhydrite

Pyrite concentrated in the stylolites

A

Anhydrite filling bigger pores

Moderate to good porosity

A

Fe

No porosity

A

Very low porosityPatchy texture

Low to moderate porosity

Fex

xVery low porosity

x

x Subtle plane parallel lamination

anhydrite

No porosity

No porosity

Py

Good porosity

14120'

14110'

2

Dep.Env.

Remarks

Sho

al

Com

plex

Tid

al F

lat

Sab

kha

Sha

llow

Lag

oon

Sho

al c

ompl

ex (

?)

Well Permit No. 1691CONTAINER CORP. OF AMERICA 34-5 #1

Figure 36.



Brian Panetta

48

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8


14290'

14300'

14310'


xx

xx

M/iP Moderate porosity

mM/iP High porosity

A

mM/iP High porosity

mM/iP

14320'

Fr

Patchy texture

Open fractures

x

Dep.Env.

Remarks

Sho

al c

ompl

ex (

?)

x

Well Permit No. 1691(cont.)CONTAINER CORP. OF AMERICA 34-5 #1




Brian Panetta

49

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8


14030'

14040'

14050'

14060'

14070'

14080'

14090'

A


A

i

M/iP/V

iP/V

A

A

Fr Fractures partially occluded by anhydrite cementStylolites with pyrite

Intraclasts horizontally aligned

Anhydrite chicken wires

A

A

Fractures filled with anhydrite

Microbial buildup Type I and Type IV-V M/V/iP

Some isolated elongated pores. Low porosity

iP/V

M/iP/V

M/iP

M/iP

Pervasive anhydrite cement occludes porosity

A

i

Moderate porosity

iP

M/V

Fr

V

Porosity almost completely obliterated by calcite cement

High porosity in the grainstones, moderate in the packstonesFr

M/iP/V

M/iP/V

High porosity

Moderate to low porosity

Thick carbonaceous laminae and anhydrite nodules iP/V/M

Very porous level

Fr

FrPatchy areas with good porosity

A

Thin levels of oncoid cortecesHigh interparticle and moldic porosity but sometimes cemented by anhydrite, Some thin intervals < 7 cm have the oncolites leachedincreasing the vuggy porosity

High porosity despite partial cementation specially along thefractures

Bivalve debris

Fractures cemented by anhydrite

x

x

xx

xx

x

x A

x

x

x

x

x

x

x

x

Dep.Env.

Remarks

Sho

al C

ompl

exM

icro

bial

Bui

ldup

Tid

al F

lat

Well Permit No. 2851M.J. BYRD ET UX 26-13 #1

Figure 37.



Brian Panetta

50

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8


14030'

14040'

14050'

14060'

14070'

14080'

14090'

14100'

14110'

14120'

14130'

A


x

x

x

x

x

x

x

x

xx

xxxx

x

x

x

A

M/V/iP

iP

iP

iP

Very low porosity

Very low porosity

Big anhydrite nodulesFractures also filled with anhydriteFr

Very high porosity

Very high porosityA

Anhydrite filling fractures

V/iP

Fr

M/iP

M/V/iP

Reef, Type II facies

M/V/iP

Fr

Fr

iP

no core

Fr

FrM/iP

Very high porosity



Fr Fractures filled with anhydrite


x Very low porosity

x

x

x

Patchy texture

Well Permit No. 2935D.R. COLEY, JR. ESTATE #35-4

iP/M

Fr

iP

iP

14020'

Dep.Env. Remarks

Sho

al C

ompl

exM

icro

bial

Ree

f Com

plex

Brecciated interval (14128-14144')

Good porosity

Qz

Good porosity

M/iP

Figure 38.



Brian Panetta

51

2

4

6

8

2

4

6

8


14150'

14140'


Very high porosity

A

Anhidrite filling fractures

V/iP

Fr

V/iP

Reef, Type II facies

A

Fr

Dep.Env.

Remarks

Mic

robi

al R

eef

Com

plex

Well Permit No. 2935 (cont.)D.R. COLEY, JR. ESTATE #35-4




Brian Panetta

52

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8


14230'

14240'

14130'

14140'

14150'

14160'

14170'

14180'

14190'

14200'

14210'

14220'

A


x

x

x

x

x

x

x

xx

x

x

x

x

x

A

A

Very low porosityAnhydrite in layers and coalesced nodules

A Very low porosity

iP

M

M

A M/V Improvement in porosity, though bigger pores are filled withanhydrite cement

M/V Carbonaceous intraclasts

M

M/V All the big pores are filled with anhydrite while the small ones are not.

M/V/iP Carbonaceous intraclasts

AVery high porosity. Big anhydrite nodules M/V/iP

High porosity

Small vugs filled with anhydrite M/V/iP

A

A

A

M/iP

M/iP

M/iP

Good porosity


Patches with high porosity

M/V/iP

A M/V/iP


M/V/iP High porosity, vugs up to 1 cm in diameter

MIcrobial buildup (Type II). May vugs filled with anhydrite

M/V/iP

Big vugs upto 2cm in diameter and sometimes elongated. Someare filled partially or totally by anhydrite

M/V/iP

A

Some elongated vugs (fractures) up to 3 cm long. Patches of very high

Moderate porosity

A

Microbial buildup Type II

Leached intraclasts

Fossil remains like spicules replaced by calcite/anhydrite

Interval with patchy texture (14196-14231'), microbial influx?

Fr

Fr

M

Fr

A

A

A

Low porosity

Concentration of pyrite in the stylolites

Low porosity

Elongated pores < 1cm

Patchy texture

porosity

Highy fractured interval (14220-14225')


x

x

x

x

x

x

A

x

i

i

i

i

Well Permit No. 2966B.C. QUIMBY 27-16 #1

Qz

Qz

Qz


Dep.Env.

Remarks

Sho

al C

ompl

ex

anhydrite

2

4

6

8

anhydrite

Tid

al F

lat

Sab

kha

Sha

llow

Sub

-wav

e B

ase

Leve

l

QzPy

Figure 39.



Brian Panetta

53

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8


14300'

14310'

14250'

14260''

14270'

14280'

14290'


x

x

x

M/iPiLeached intraclastsFossil debris resembling spicules replaced by anhydrite

M/iP

V/iP

Very low porosity

Very low porosity

Oncolites disposed in thin levels

M/iP

M/V/iP

M/V/iP

M/V/iP

Low porosity

Moderate to high porositySome vugs are filled with anhydrite/calcite

or i

AM/iP

Very low porosity

or

A

A

Interval with patchy texture (14290-14295'). Microbial influence?V

Interval with patchy texture and high vuggy porosity (14276-14288'). Microbial influence?

V

V

Spicules


or

x

x

x

x

x

FriP/V

Qz

Qz

Qz

Dep.Env.

Remarks

2

4

6

8

Sha

llow

Sub

-wav

e B

ase

Leve

l

Well Permit No. 2966 (cont.)B.C. QUIMBY 27-16 #1




Brian Panetta

54

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8


14020'

14030'

14040'

14050'

14060'

14070'

14080'

14090'

A


xx

x

x

xxx

x

x

xx

xx

xx

xx

x

x

x

x

x

x

x

M/V/iP

Layered and nodular anhydrite interbedded with the mudstone


A

A

Layered and nodular anhydriteA

A

A

FeHigh fenestral porosity completely filled with calcite as well as somefracturesType IV and V

A Fr

Ip

A

A

Very low porosity level

Highly porous grainstonesLow to moderate porosity

Very high porosity

Oncolites>1cm

M/V/iP

M/V/iP

Porosity obliterated by An/Ca

Porosity obliterated by anhydrite/calcite

A

Type IV/V microbial facies

Fe M/V/iP

Fenestral porosity obliterated by An/CaModerate porosity

A

FrVery low porosity

M/V/iPFr

Pores occluded by anhydrite

A M/V

No porosity

Type IV and V

No porosity

iP/V

Moderate to high porosity

Bivalve fragments

A

A

Abundant clayey laminae.

Very low porosity

Big anhydrite nodules, aprox. 5cm diam


Oncolites up to 3mm in diam. and stromatolites

Very low porosity

Stylolites with pyiriteVery thin mudstone levels interbedded

xGood porosity

x

x

x

x

x

i

PyFr

Py

i

i

14010'

14100'

M/V/iP

Dep.Env.

Remarks

Sho

al C

ompl

ex

anhydrite

anhydrite

Tid

al F

lat

Sab

kha

Sha

llow

Lag

oon

Well Permit No. 3412B.C. QUIMBY 27-15 #2

Figure 40.



Brian Panetta

55

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8


14020'

14030'

14040'

14050'

14060'

14070'

14080'

14090'

14100'

14110'

A


x

xx

x

x

x

x

x

xx

x

x

x

xx

x

xx

x

x

x

xx

x

x

x

x

x

x

xx

x

x

Anhydrite cement

No porosity

The microbial buildup is mainlyType I and in minor degree Type IV and V. High porosity, though in thin intervals it is completely occluded by calcite cement

V

A

A

Intervals with vuggy/moldic porosity, sometimes occluded with anhydrite or calcite cementSome thin wackestone layers interbedded.

Interval with very low porosity (14064-14070)

14015-14025: interval with very low porosity

M/V

Microbial buildup Type IV and V

iP

M/V

M/V

M/V

Enhancement in porosity due to ooids/peloids dissolution M/V/Ip

no core

no core

i

i

i

i

i

A

iP/V

M/V

iP

Fr

iP

iP

iP

Fr

Fr

Porosity almost completely cemented

Fractures partially infilled with anhidrite/calcite cement

Elongated muddy intraclasts<1cm long

Pores partially obliterated by calcite cement

Pyrite

Fe

High porosity interval (14071-14075)

Moderate to good porosity from 14028 to 14044

x

x

Well Permit No. 3739BERTHA C. QUIMBY 34-1 #1

Py

Good porosity

PyQz

Qz

Fe

Qz

PyQz

Low porosity

Abundant siliceous grains

Good porosity

Dep.Env.

RemarksS

hoal

Com

plex

Tid

al F

lat

Oncoidal cortex

Sha

llow

Lag

oon

Mic

robi

al

Ree

f Com

p. Figure 41.



Brian Panetta

56

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8


14270'

14280'

14290'

14300'

14310'

14320'

A


i

M/iP

Very low porosity

i Carbonaceous intraclasts

i Carbonaceous intraclasts

10-15cm thick layers

Very low porosity

Alternation of 40-60cm thick ws/ps beds and 8-15cms ps/gs layers

A

A

Very low porosity

M/iP

M/iP

Low porosity

Wackestone rich in carbonaceous material

Glauconite

Alternation of 40-60cm thick ws/ps beds and 8-15cms ps/gs layers

M/iP

M/iP

Discontinuous lamination

Fr Thin fractures cemented by anhydrite

Interval with moderate to good porosity (14288-14300')

No visible porosity

A

A

Fe Fenestral porosity filled with cement

x

x

x

x

x

x

Dep.Env.

Remarks

Sho

al C

ompl

exS

hallo

w S

ub W

ave

Leve

l T

idal

Fla

t

Figure 42.



Fr Thin fractures cemented by anhydriteModerate to good porosity

Well Permit No. 3990D.R. COLEY, III UNIT 26-2 #1

Brian Panetta

57

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6


13940'

13950'

13960'

13970'

13980'

13990'

14000'

14010'

13930'

A


Basement

x

x

x

x

x

xx

xx

x

x

x

x

x

x

x

xx

x

iP

M/iP

iP

iP

iP

iP

iP

A

A

A

Fr

FrA

A Fr

A

A

Abundant anhydrite nodules

Cross stratification

Very high porosity

Very high porosity

Very thin more cemented layers within the grainstone

Grainstone with leached ooids

Big calcite nodules. Low porosity




Interbedding of layers of wackestone and very thin darker layers of mudstone

Lithoclasts

Big anhydrite nodules

Wavy discontinuous lamination

Abundant lithoclasts

Angular to subangular feldspar grains up to 4cms, with an averageof 1cm. Bad sorting

No porosity

No porosity

Very low porosity

Presence of very thin beds of black matrix with lithoclasts floating in it.

x

x

x

x

x

A

V/M/iP

Chloritized granite

No porosity

No porosity

No porosity

No porosity

Very low porosity

13920'

Dep.Env.

Remarks

Sho

al C

ompl

exT

idal

Fla

tS

hallo

w L

agoo

n

Well Permit No. 5779NEUSCHWANDER 34-3 #1

iP/V

No porosity

Figure 43.



Brian Panetta

58

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8

2

4

6

8


13980'

13990'

14000'

14010'

14020'

14030'

A


V/iP

A

V/iP

Some thin (3-4cm) intervals with M/mV

Some pores filled in with anhydrite

High porosity due to oolite dissolution M/V/iP

AHighly fractured interval. Anhydrite cements the joints partially

Moderate porosity. Fractures are partially filled with anhydrite V/iP/Fr

Oncoid cortices. Good porosity due to allochems dissolution Abundant anhydrite veins

M/V

Thin microbial buildup layers interbedded with the wackestonesLow porosity. Some vuggy (fenestral?) porosity occludded by

Microbial buildup, Type I mainly. Vertical burrowsM/V

Fractured interval, diagenetic breccia. Nodular/layered anhidrite

Abundant elongated vugs

Anhydrite nodules.High vuggy porosity. White crust lining the vugs.Vertical burrows and fracturesOncolite levels interbeded with wackestone layers with abundant stylolites

Fr

Very low porosity

A

iP/V

Pyrite disseminatedanhydrte cement.

Fr

Fr

xA

x

x Moderate to good porosity

x

x

xx

x

x

Dep.Env.

Remarks

Sho

al C

ompl

exS

hallo

w L

agoo

nT

idal

Fla

tWell Permit No. 7588BBLACKSHER 27-11 #1

Figure 44.

Core description for well permit # 7588B.


Brian Panetta

59

Table 5. Characterization of Smackover Lithofacies in the Vocation Field Area.

Lithofacies Lithology Allochems Pore Types Porosity(percent)

Permeability(md)

ooid-dominated,grain-supported

(grainstone/packstone)

dolostone,limestone

ooids, oncoids,peloids

moldic,interparticulate,intercrystalline

high(1.5-28.3)

high(0-2,230)

ooid-dominated,matrix-supported

(wackestone)

dolostone ooids, oncoids,peloids

moldic moderate(1.2-14.0)

moderate(0-8)

oncoid-dominatedgrain-supported

(grainstone/packestone)

dolostone oncoids,peloids, ooids,

intraclasts

interparticulate,moldic, vuggy

high(1.6-20.1)

high(0-1,635)

oncoid-dominatedmatrix-supported

(wackestone)

dolostone oncoids,peloids

vuggy, moldic low(2.5-8.3)

low(0-0.39)

peloid-dominatedgrain-supported

(grainstone/packestone)

dolostone,limestone

peloids,oncoids, ooids

interparticulate,intercrystalline,

vuggy

high(0.8-25.6)

high(0-587)

peloid-dominatedmatrix-supported

(wackestone)

dolostone,anhydriticdolostone

peloids,oncoids

intercrystalline moderate(1.0-18.2)

moderate(0-39)

mudstone dolostone,limestone

none fracture low(1.2 to 8.8)

low(<0.01)

algal stromatolite(boundstone)

dolostone algae, peloids,oncoids

fracture, vuggy,fenestral

low(1.1-8.8)

moderate(0-16)

algal boundstone dolostone algae, peloids,oncoids

vuggy, fracture,breccia, moldic

high(3.0-33.6)

high(0-2,998)

Brian Panetta

60

P-57

79

P-11

185

P-29

66

P-29

35

P-47

86-B

P-37

39

P-29

78

P-42

25

P-19

56

P-33

42

P-16

91

P-16

91E

P-16

38

P-75

88-B

P-18

30

P-15

99

P-34

12

P-28

51

4650

00

4600

00

510000

515000

-13700

-13800

-13900

-13750-13750

-13850

-139

00

-13700

-13800

-13900

-13650

-13750

-13850

-138

00

-139

00

-138

50

0'50

00'

2500

'

Ho

rizo

nta

l Sca

le

Co

nto

ur I

nte

rval

= 2

5 fe

et

oil

wel

l

dry

wel

l

aban

do

ned

oil

wel

l

salt

wat

er d

isp

osa

l wel

l

bas

emen

t

-13800

By

Juan

C. L

linas

Figu

re 4

6. C

onto

ur m

ap o

f the

top

of th

e m

icro

bial

reef

com

plex

.

Brian Panetta

61

crys

talli

ne

bas

emen

t

oil

wel

l

dry

wel

l

aban

do

ned

oil

wel

l

salt

wat

er d

isp

osa

l wel

l

fau

lt, b

lock

on

do

wn

thro

wn

sid

e

N

P-57

79

4550

00

4600

00

4650

00

4700

00

510000

515000

520000

P-61

55

P-39

90P-30

29

P-11

185

P-28

51P-

2966

P-29

35

P-47

86-B

P-37

39

P-29

78

P-42

25

P-19

56

P-33

42 P-16

91

P-16

91E

P-16

38

P-75

88-B

P-18

30

P-15

99P-

3412

P-10

126

Vert

ical

Sca

le

-14,

000'

-13,

900'

-13,

800'

-13,

700'

-13,

600'

-13,

500'

-14,

100'

0'50

00'

2500

'

Ho

rizo

nta

l Sca

le

By

Juan

C. L

linas

Figu

re 4

7. S

truct

ure

cont

our m

ap o

f the

top

of th

e Sm

acko

ver F

orm

atio

n.

Brian Panetta

62

0' 5000'2500 '

Horizontal Scale

Contour Interval = 25 feet

P-577977P

P-6155

P-11185

P-2966

P-2935

P-4786-B

P-3739

P-2978

P-4225225

P-1956

P-3342

P-1691-1

P-1691E- 66991E

P-1638P 61P-

P-7588-BP-1830

P-1599

P-3412

050

150100

400

350

300250200

250

300

250

250

300

350

50

150100

250200

400

350

300

250

300

250

300250

350

250

300

50

150200

P-2851

465000

460000

5100

00

5150

00

N

0

00

50

oil well

dry well

abandoned oil well

salt water disposal well

basement

By Juan C. Llinas

Figure 48. Isopach map of the Smackover Formation.

Brian Panetta

63

P-57

79

P-11

185

P-29

66

P-29

35

P-47

86-B

P-37

39

P-29

78

P-42

25

P-19

56

P-33

42

P-16

91

P-16

91E

P-16

38

P-75

88-B

P-18

30

P-15

99

P-34

12

P-28

51

050

100

100

100

200

150

050

150

4650

00

4600

00

510000

515000

0'50

00'

2500

'

Ho

rizo

nta

l Sca

le

Co

nto

ur I

nte

rval

= 2

5 fe

et

oil

wel

l

dry

wel

l

aban

do

ned

oil

wel

l

salt

wat

er d

isp

osa

l wel

l

bas

emen

t By

Juan

C. L

linas

Figu

re 4

9. I

sopa

ch m

ap o

f the

mic

robi

al re

ef c

ompl

ex.

Brian Panetta

64

DATU

M: T

op o

f the

Buc

kner

Anh

ydrit

e M

embe

r

Wel

l 169

1W

ell 1

691-

E

Wel

l 163

8

Wel

l 373

9

Wel

l 293

5

100'0'

200'

300'

400'

500'

No h

orizo

ntal

Sca

le

WE

AA

'

Wel

l 334

2

CRYS

TALL

INE

BAS

EMEN

T

REEF

COM

PLEX

SHAL

LOW

LAGO

ON

SHOA

LCO

MPL

EXSA

BKHA

/TI

DAL F

LAT

SHAL

LOW

SUB

-W

AVE

BASE

NORP

HLET

FORM

ATIO

N

GR

DPH

I

NPH

I

Co

red

inte

rval

sCR

YSTA

LLIN

EDO

LOST

ONE

By

Juan

C. L

linas

Figu

re 5

0. C

ross

sec

tion

acro

ss V

ocat

ion

Fiel

d.

Brian Panetta

65

that Strago contributed to the project. Typical seismic profiles for the field illustrating the reef

reservoir are shown in (Figure 51). The multi-attribute seismic study of the field continues.

Task 2—Rock-Fluid Interactions.--This task is a continuation of the study of reservoir

architecture and heterogeneity at the microscopic scale. While macroscopic and mesoscopic

heterogeneities are largely a result of structural and depositional processes, microscopic

heterogeneities are often a product of diagenetic modification of the pore system. Macroscopic

and mesoscopic heterogeneities influence producibility by compartmentalizing the reservoir and

providing barriers to large-scale fluid flow. Microscopic heterogeneities, on the other hand,

influence producibility by controlling the overall rate of fluid flow through the reservoir. This

task will involve an expansion of previous general studies of diagenesis within the Smackover

and will identify those diagenetic processes that have influenced reef and shoal carbonates in

paleohigh reservoirs using Appleton and Vocation Fields as models. This work will document

the impact of cementation, compaction, dolomitization, dissolution and neomorphism on reef

and shoal reservoirs. A detailed paragenetic sequence will be constructed for reservoir

lithologies in each field to document the diagenetic history of these lithologies and to determine

the timing of each individual diagenetic event. Attention will be focused on spatial variation in

diagenesis within each field and also in variations in diagenesis between fields. The influence of

paleohigh relief on diagenesis will be identified. This work will incorporate petrographic, XRD,

SEM, and microprobe analyses to characterize, on a microscopic scale, the nature of the pore

system in the Appleton and Vocation reservoirs. This task will focus on the evolution of the pore

systems through time and on the identification of those diagenetic processes that played a

significant role in the development of the existing pore systems. The ultimate goal of the task is

to provide a basis for characterization of porosity and permeability with the reef and shoal

reservoirs.

Brian Panetta

66

Figure 51. Interpreted seismic lines in Vocation Field.

Brian Panetta

67

68

Thin sections (379) have been studied from 11 cores from Appleton Field to determine the

impact of cementation, compaction, dolomitization, dissolution and neomorphism has had on the

reef and shoal reservoirs in this field. Thin sections (237) have been studied from 11 cores from

Vocation Field to determine the paragenetic sequence for the reservoir lithologies in this field.

An additional 73 thin sections have been studied for the shoal and reef lithofacies in Vocation

Field to identify the diagenetic processes that played a significant role in the development of the

pore systems in the reservoirs at Vocation Field.

The petrographic analysis and pore system studies essentially have been completed. Table 2

summarizes the petrographic characteristics for the Smackover lithofacies in Appleton Field, and

Table 5 summarizes these characteristics for the Smackover in Vocation Field. Figure 52

presents a paragenetic sequence for the Smackover at Vocation Field. Pore system studies

continue.

Task 3—Petrophysical and Engineering Property Characterization.--This task will

focus on the characterization of the reservoir rock, fluid, and volumetric properties of the

reservoirs at Appleton and Vocation Fields. These properties can be obtained from petrophysical

and engineering data. This task will assess the character of the reservoir fluids, as well as

quantify the petrophysical properties of the reservoir rock. In addition, considerable effort will

be devoted to the rock-fluid behavior (i.e., capillary pressure and relative permeability). The

production rate and pressure histories will be cataloged and analyzed for the purpose of

estimating reservoir properties such as permeability, well completion efficiency (skin factor),

average reservoir pressure, as well as in-place and movable fluid volumes. A major goal is to

assess current reservoir pressure conditions and develop a simplified reservoir model. New

pressure and tracer survey data will be obtained to assess communication within the reservoir at

DiageneticEvent

Eogenetic StageMesogenetic Stage

marine water fresh water brine reflux

Micritization

Early Calcite

Cementation

Dissolution of

Aragonite

Dolomitization

Mechanical

Compaction

Fracturing

Chemical

Compaction

Non-selective

Dissolution

Hydrocarbon

Migration

Siliceous

Cementation

Calcite

Cementation

Anhydrite

Cementation

porosity not modified porosity generation porosity occlusion

Depth of Burial Increase

Time Increase

moldic

fracture

vuggy

intercrystalline intercrystalline

Figure 52. Diagenetic sequence of the Smackover Formation at Vocation Field.

Brian Panetta

69

70

Appleton and Vocation Fields, including among and within the various pay zones in the

Smackover. This work will serve as a guide for the reservoir simulation modeling. Petrophysical

and engineering data are fundamental to reservoir characterization. Petrophysical data are often

considered static (non-time dependent) measurements, while engineering data are considered

dynamic (time-dependent). Reservoir characterization is the coupling or integration of these two

classes of data. The data are analyzed to identify fluid flow units (reservoir-scale flow

sequences), barriers to flow, and reservoir compartments. Petrophysical data are essential for

defining the quality of the reservoir, and engineering data (performance data) are crucial for

assessing the producibility of the reservoir. Coupling these concepts, via reservoir simulation or

via simplified analytical models, allows for the interpretation and prediction of reservoir

performance under a variety of conditions. The first phase of the task involves the review,

cataloging, and analysis of available core measurements and well log data. This information will

be used to classify porosity, permeability, oil and water saturations, grain density, hydrocarbon

show, and rock type for each foot of core. Core data will be correlated to the well log responses,

and porosity-permeability relationships will be established for each lithofacies evident in the

available data. The next phase involves the measurement of basic relative permeability and

capillary pressure relations for the reservoir from existing cores. These data will be compiled and

analyzed and then used for reservoir simulation and waterflood/enhanced oil recovery

calculations. The third phase focuses on the collection and cataloging of fluid property (PVT)

data. In particular, basic (black oil) fluid property data are available, where these analyses

include standard measurements of gas-oil-ratio (GOR), oil gravity, viscosity, and fluid

composition. The objective of the fluid property characterization work is to develop relations for

the analysis of well performance data and for reservoir simulation. The final phase will be to

71

develop a performance-based reservoir characterization of Appleton and Vocation Fields. This

phase will focus exclusively on the analysis and interpretation of well performance data as a

mechanism to predict recoverable fluids and reservoir properties. This analysis will focus on the

production data, but any other well performance data will also be considered, in particular,

pressure transient test data and well completion/stimulation data will also be analyzed and

integrated into the reservoir description. Historical pressure data will be compared to new

pressure and tracer survey data for wells obtained as part of this work. The material balance

decline type curve analysis will be emphasized for the analysis of the data.


Appleton Field. Petrophysical and engineering property data have been gathered and

tabulated for Appleton Field. These data include oil, gas and water production, fluid property

(PVT) analyses and porosity and permeability information (Tables 6 and 7). Porosity and

permeability characteristics of Smackover facies have been analyzed for each well using porosity

histograms (Figures 53-57), permeability histograms (Figures 58-62) and porosity versus depth

plots (Figures 63-67). Log porosity versus core porosity and porosity versus permeability plots

for wells in the field have been prepared (Figures 68-72). Porosity versus permeability cross

plots for Smackover facies have been prepared (Figures 73-77). Well performance studies

through type curve (Table 8 and Figures 78-82) and decline curve analyses (Figures 83-87) have

been completed for the wells in the field. The original oil in place and recoverable oil remaining

for the field have been calculated (Table 9 and Figures 88-95).

Vocation Field. Petrophysical and engineering property data have been gathered and

tabulated for Vocation Field. These data include oil, gas and water production, fluid property

(PVT) analyses and porosity and permeability information (Tables 10-14). Porosity and

72

Table 6 — Porosity and permeability characteristics in the Smackover. Well

Minimum Porosity, (percent)

Maximum Porosity, (percent)

Average Porosity, (percent)

Minimum Permeability,(md)

Maximum Permeability,(md)

Geometric Average Permeability,(md)

3854B 3.2 24.4 13.6 0.54 618.1 21.8 3986 9.7 29.0 15.7 6.1 2200 108.3 4633B 9.2 24.1 17.0 0.37 1349 103.9 4835B 4.0 24.4 15.0 0.46 3345 191.4 6247B 1.0 6.7 2.7 0.055 0.1 0.07 Table 7 — Porosity and permeability characteristics in the Reef. Well




Minimum Permeability,(md)

Maximum Permeability,(md)

Geometric Average Permeability,(md)

3854B N/A N/A N/A N/A N/A N/A 3986 10.7 22.1 14.5 8.9 1545 115.6 4633B 10.5 25.0 18.4 13.4 1748 274.0 4835B 16.0 20.8 17.9 225.8 563.8 345.9 6247B 1.0 14.3 5.6 0.025 18.8 1.79

73

Fig. 53 — Core Porosity Histogram, Appleton Well 3854B

74

Fig. 54 — Core Porosity Histogram, Appleton Well 3986


75



76

Fig. 58 — Core Permeability Histogram, Appleton Well 3854B

Fig. 59 — Core Permeability Histogram, Appleton Well 3986

77



78


79

Fig. 63 — Porosity Variation with Depth, Appleton Well 3854B

80

Fig. 64 — Porosity Variation with Depth, Appleton Well 3986

81


82


83


84

Fig. 68 — Log Porosity versus Core Porosity, Appleton Well 3854B

Fig. 69 — Log Porosity versus Core Porosity, Appleton Well 3986

85



86


Fig. 73 — Core Permeability versus Core Porosity, Appleton Well 3854B.

87

Fig. 74 — Core Permeability versus Core Porosity, Appleton Well 3986.


88



89

Table 8 — Parameters Derived from Type Curve Analysis.

Well

Nct (STB/ps

i)

N (MSTB)

A (acres)

ko (md)

s (dim-less)

3854B 471.6 25630 1600.5 1.14 -7.6 3986 50.1 2725 35.6 0.06 -5.7

4633B 510.1 27720 680.9 1.86 0.09 4835B 355.4 19320 617.6 3.00 0.12 6247B 62.8 3411 229.0 1.14 -4.7 Total = 78806

90

Fig. 78 — Type Curve Match, Appleton Well 3854.

Fig. 79 — Type Curve Match, Appleton Well 3986.

91

Fig. 80 — Type Curve Match, Appleton Well 4633B.


92


93

Fig. 83 — Estimate of Recoverable Oil, Appleton Well 3854B.

Fig. 84 — Estimate of Recoverable Oil, Appleton Well 3986.

94



95


96

Table 9 – Oil Recovery and Recovery Factors.

Well

Nrecoverable (MSTB)

Np

(MSTB)

N

(MSTB)

Recovery Factor Np/N

(dim-less)

3854B 410 410 25630 0.016 3986 160 160 2725 0.059

4633B 1160 1150 27720 0.041 4835B 783 780 19320 0.040 6247B 186 180 3411 0.053 Total = 2699 = 2680 = 78806 = 0.034

97

Fig. 88 — Recoverable Oil (EUR Analysis) versus Computed Original Oil-in-Place (Decline Type Curve Analysis), Appleton Oil Field.

Fig. 89 — Computed Original Oil-in-Place versus Completion Date, Appleton Oil Field.

98

Fig. 90 — Recoverable Oil versus Completion Date, Appleton Oil Field.

Fig. 91 — Flow Capacity versus Completion Date, Appleton Oil Field.

99

Fig. 92 — Flow Capacity versus Recoverable Oil, Appleton Oil Field.

Fig. 93 — Contour Map of Flow Capacity, Appleton Oil Field.

100

Fig. 94 — Contour Map of Original Oil-in-Place, Appleton Oil Field.

Fig. 95 — Contour Map of Recoverable Oil, Appleton Oil Field.

101

Table 10 — Porosity and permeability characteristics in the Sabkha Interval.

Well




Minimum

Permeability,(md)

Maximum

Permeability,(md)

Geometric Average

Permeability,(md)

1599 N/A N/A N/A N/A N/A N/A 1830 N/A N/A N/A N/A N/A N/A 2851 N/A N/A N/A N/A N/A N/A 2935 N/A N/A N/A N/A N/A N/A 3412 1.1 6.6 2.4 0.1 0.1 0.1 3739 N/A N/A N/A N/A N/A N/A 4225 2.3 2.5 2.4 N/A N/A N/A 5779 N/A N/A N/A N/A N/A N/A 11185 0.9 14.6 8.3 N/A N/A N/A

Table 11 — Porosity and permeability characteristics in the Tidal Flat Interval.

Well




Minimum

Permeability,(md)

Maximum

Permeability,(md)

Geometric Average

Permeability,(md)

1599 N/A N/A N/A N/A N/A N/A 1830 14.6 23.6 21.3 5.9 162.0 56.6 2851 1.0 12.0 7.0 7.9 14.1 11.0 2935 N/A N/A N/A N/A N/A N/A 3412 2.4 10.9 5.5 0.3 10.4 1.5 3739 3.7 8.6 5.1 9.0 9.0 9.0 4225 1.2 3.5 2.0 0.04 0.04 0.04 5779 2.1 3.7 2.9 N/A N/A N/A 11185 0.9 9.9 5.1 0.13 75.0 3.3

102

Table 12 — Porosity and permeability characteristics in the Shoal Complex Interval.

Well

Minimu

m Porosity, (percent)



Minimum

Permeability,(md)

Maximum

Permeability,(md)

Geometric Average

Permeability,(md)

1599 N/A N/A N/A N/A N/A N/A 1830 10.7 22.0 15.8 5.6 400.0 54.0 2851 2.1 20.1 9.9 0.02 1321.5 8.6 2935 1.6 15.3 9.7 0.05 57.0 4.5 3412 1.7 15.3 6.4 0.2 466.7 15.8 3739 1.6 13.7 7.9 0.04 18.0 1.8 4225 0.8 13.0 5.1 0.04 266.0 1.8 5779 2.7 21.9 13.3 0.04 1263.0 44.7 11185 N/A N/A N/A N/A N/A N/A

Table 13 — Porosity and permeability characteristics in the Lagoon Interval.

Well




Minimum

Permeability,(md)

Maximum

Permeability,(md)

Geometric Average

Permeability,(md)

1599 8.0 19.0 12.5 2.8 1119.2 31.3 1830 2.5 15.3 7.6 0.3 57.0 4.1 2851 N/A N/A N/A N/A N/A N/A 2935 N/A N/A N/A N/A N/A N/A 3412 1.7 11.1 4.3 0.2 8.6 1.1 3739 1.8 14.0 5.7 0.02 50.0 1.4 4225 2.0 7.5 3.4 0.02 0.2 0.06 5779 1.9 8.1 2.7 0.02 2.2 0.1 11185 N/A N/A N/A N/A N/A N/A

103

Table 14 — Porosity and permeability characteristics in the Reef Interval.

Well




Minimum

Permeability,(md)

Maximum

Permeability,(md)

Geometric Average

Permeability,(md)

1599 2.5 33.6 9.3 0.8 5730.0 71.9 1830 5.2 18.6 12.1 0.3 196.0 12.0 2851 2.7 24.9 12.3 0.06 740.0 29.2 2935 3.2 18.3 8.2 0.02 332.0 5.8 3412 N/A N/A N/A N/A N/A N/A 3739 1.7 7.8 5.5 2.7 68.0 10.3 4225 N/A N/A N/A N/A N/A N/A 5779 N/A N/A N/A N/A N/A N/A 11185 N/A N/A N/A N/A N/A N/A

104

permeability characteristics of Smackover facies have been analyzed for each well using porosity

histograms (Figures 96-104), permeability histograms (Figures 105-113) and porosity versus

depth plots (Figures 114-122). Log porosity versus core porosity for wells in the field have been

prepared (Figures 123-131). Porosity versus permeability cross plots for wells (Figures 132-139)

and for Smackover facies have been prepared (Figures 140-143). Well performance studies

through type curve (Figures 144-153 and Table 15) and decline curve analyses (Figures 154-

163) have been completed for the wells in the field. Figure 164 presents an alternative

calculation of recoverable oil. The original oil in place and recoverable oil remaining for the

field have been calculated (Table 16 and Figures 165-172).

Task 4—Data Integration.--This task will integrate the geological, geophysical,

petrophysical and engineering data into a comprehensive digital database for reservoir

characterization, modeling and simulation. Separate databases will be constructed for Appleton

and Vocation Fields. This task serves as a critical effort to the project because the construction of

a digital database is an essential tool for the integration of large volumes of data. This task also

serves as a means to begin the process of synthesizing concepts. The task will involve entering

geologic data and merging these data with geophysical imaging information. Individual well logs

will serve as the standard from which the data are entered and compared. The data will be

entered at 1-foot intervals. All well logs in the fields will be utilized. The researchers will

resolve any apparent inconsistencies among data sets through an iterative approach. This task

also will involve entering petrophysical data, rock and fluid property data, production data,

including oil, gas and water production, and well completion data, including perforated intervals,

completion parameters, well stimulation information, etc. A validation effort will be conducted

to resolve any apparent inconsistencies among data sets through an iterative approach.

105

Fig. 96 — Core Porosity Histogram, Vocation Well 1599.


106



107



108



109


110

Fig. 105 — Core Permeability Histogram, Vocation Well 1559.


111



112



113



114


115

Fig. 114 — Porosity Variation with Depth, Vocation Well 1599.

116


117


118


119


120


121


122


123


124

Fig. 123 — Log Porosity versus Core Porosity, Vocation Well 1599.


125



126



127



128


129

Fig. 132 — Core Permeability versus Core Porosity, Vocation Well 1599.


130



131


Fig. 137 — Core Permeability versus Core Porosity, Vocation Well 3739

132



133

Fig. 140 — Core Permeability versus Core Porosity, Tidal Flat.

Fig. 141 — Core Permeability versus Core Porosity, Shoal.

134

Fig. 142 — Core Permeability versus Core Porosity, Lagoon.

Fig. 143 — Core Permeability versus Core Porosity, Reef.

135

Fig. 144 — Type Curve Match, Vocation Well 1599.


136



137



138


Fig. 151 — Type Curve Match, Vocation Well 4225B.

139



140

Table 15 — Parameters Derived from Type Curve Analysis.

Well

Nct (STB/psi)

N (MSTB)

A (acres)

ko (md)

s (dim-less)

1599 64.6 2,750 369.6 3.68 0.38 1830 260.9 11,100 2861.4 3.20 0.63 2851 87.0 3,705 348.8 0.28 -3.72 2935 53.3 2,267 167.5 0.45 0.78 3412 13.9 595 191.0 0.90 0.72 3739 193.8 8,247 987.0 1.39 -0.10 4225 61.3 2,608 216.3 0.005 -5.2

4225B 8.7 371 246.3 4.72 0.58 5779 25.5 1,086 328.4 0.53 -6.26 11185 25.9 1,103 53.3 0.15 -4.96 Total = 33,382

141

Fig. 154 — Calculation of Recoverable Oil, Vocation Well 1599.


142



143



144


Fig. 161 — Calculation of Recoverable Oil, Vocation Well 4225B.

145



146

Fig. 164 — Alternative Calculation of Recoverable Oil, Vocation Well 11185.

147

Table 16 – Oil Recovery and Recovery Factors.

Well

Nrecoverable (MSTB)

Np

(MSTB)

N

(MSTB)

Recovery Factor Np/N

(dim-less) 1599 170 169 2,750 0.061 1830 735 733 11,100 0.066 2851 402 388 3,705 0.105 2935 168 165 2,267 0.072 3412 37 36 595 0.061 3739 534 529 8,247 0.064 4225 55 47 2,608 0.018

4225B 31 29 371 0.078 5779 119 102 1,086 0.094 11185 145 120 1,103 0.109 Total = 2,331 = 2,318 = 33,832 = 0.069

148

Fig. 165 — Recoverable Oil (EUR Analysis) versus Computed Original Oil-in-Place (Decline Type Curve Analysis), Vocation Oil Field.

Fig. 166 — Computed Original Oil-in-Place versus Completion Date, Vocation Oil Field.

149

Fig. 167 — Recoverable Oil versus Completion Date, Vocation Oil Field.

Fig. 168 — Flow Capacity versus Completion Date, Vocation Oil Field.

150

Fig. 169 — Flow Capacity versus Recoverable Oil, Vocation Oil Field.

151

Fig. 170 — Contour Map of Flow Capacity, Vocation Oil Field.

Fig. 171 — Contour Map of Original Oil-in-Place, Vocation Oil Field.

152

Fig. 172 — Contour Map of Recoverable Oil, Vocation Oil Field.

153

All geological, geophysical, petrophysical and engineering data generated to date from this

study have been entered and integrated into digital databases for Appleton and Vocation Fields.

3-D Modeling (Phase 2)

Task 5—3-D Geologic Model.--This task involves using the integrated database which

includes the information from the reservoir characterization tasks to build a 3-D stratigraphic and

structural model(s) for Appleton and Vocation Fields. For Appleton Field, the existing, but

independently completed, geological and geophysical studies will be integrated and used in

combination with the new information from the drilling and producing of the sidetrack well in

the field and from the study of the additional five cores and additional 3-D seismic data from the

field area to revise, as needed, the current Appleton geologic model. The Appleton reef-shoal

paleohigh (low-relief) model will be applied to Vocation Field (high-relief paleohigh). The

application of the Appleton model to Vocation Field could result in the Appleton model being

reasonable for modeling the Vocation reservoir or could result in the need to modify the

Appleton model to honor the characteristics of the Vocation reservoir and structure. The result,

therefore, could be a single geologic model for reef-shoal reservoirs associated with basement

paleohighs of varying degrees of relief or two geologic models—one for reef-shoal reservoirs

associated with low-relief paleohighs and one for reef-shoal reservoirs associated with high-

relief paleohighs. This task also provides the framework for the reservoir simulation modeling in

these fields. Geologic modeling sets the stage for reservoir simulation and for the recognition of

flow units, barriers to flow and flow patterns in the respective fields. Sequence stratigraphy in

association with structural interpretation will form the framework for the model(s). The model(s)

will incorporate data and interpretations from sequence stratigraphic, depositional history and

structural studies, core and well log analysis, petrographic and diagenetic studies, and pore

154

system and petrophysical analysis. The model(s) will also incorporate the geologic observations

and interpretations made from studying stratigraphic and spatial lithofacies relationships

observed in Late Jurassic microbial reefs in outcrops. The purpose of the 3-D geologic model(s)

is to provide an interpretation for the interwell distribution of systems tracts, lithofacies, and

reservoir-grade rock. This work is designed to improve well-to-well predictability with regard to

reservoir parameters, such as lithofacies, diagenetic rock-fluid alterations, pore types and

systems, and heterogeneity. The geologic model(s) and integrated database become effective

tools for cost-effective reservoir management for making decisions regarding operations in these

fields. Accepted industry software, such as Stratamodel and GeoSec, will be used to build the

3-D geologic model(s). GeoSec software will be used in the 3-D structural interpretation and

Stratamodel software will be used to construct the geologic model(s).

3-D geologic modeling of the structures and reservoirs at Appleton and Vocation Fields has

been completed. The model for the structure and reservoir characteristics at Appleton Field are

illustrated in Figures 173-174 and Figures 175-176, respectively. The model for the structure and

reservoirs at Vocation Field are shown in Figures 177-178 and Figures 179-180, respectively.

The model represents an integration of geological, petrophysical and seismic data.

Task 6—3-D Reservoir Simulation Model.--This task focuses on the construction,

implementation and validation of a numerical simulation model(s) for Appleton and Vocation

Fields that is based on the 3-D geologic model(s), petrophysical properties, fluid (PVT)

properties, rock-fluid properties, and the results of the well performance analysis. The geologic

model(s) will be coupled with the results of the well performance analysis to determine flow

units, as well as reservoir-scale barriers to flow. Reservoir simulation will be performed

155

Fig. 173 – 3-D model of Appleton Field structure on top of the Smackover/Buckner.

156

Figure 174. 3-D model of Appleton Field structure on top of the reef interval.

157

Fig. 175 –Cross section showing reservoir porosity at Appleton Field.

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0.05

0.10

0.15

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158

Fig. 176 –Cross section showing permeability at Appleton Field.

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163

separately for cases of the Appleton and Vocation Fields to determine if a single simulation

model can represent these reef-shoal reservoirs. However, because these reservoirs are

associated with basement paleohighs of varying degrees of relief, two simulation models may be

required—one for reef-shoal reservoirs associated with low-relief paleohighs (Appleton) and one

for reef-shoal reservoirs associated with high-relief paleohighs (Vocation). The purpose of this

work is to validate the reservoir model with history-matching, then build forecasts that consider

the following scenarios: 1) base case (continue field management as is); 2) optimization of

production practices (optimal well completions, including stimulation); 3) active reservoir

management (new replacement and development wells); and 4) initiation of new recovery

methodologies (targeted infill drilling program and/or possible enhanced oil recovery scenarios).

The purposes of reservoir simulation are to forecast expected reservoir performance, to forecast

ultimate recovery, and to evaluate different production development scenarios. We will use

reservoir simulation to validate the reef-shoal reservoir model, then extend the model to predict

performance for a variety of scenarios (as listed above). Our ultimate goals in using reservoir

simulation are to establish the viability of a simulation model for a particular reservoir, then

make optimal performance predictions. Probably the most important aspect of the simulation

work will be the setup phase. The Smackover is well known as a geologically complex system,

and our ability to develop a representative numerical model for both the Appleton and Vocation

Fields is linked not only to the engineering data, but also to the geological, petrophysical, and

geophysical data. We expect to gain considerable understanding regarding carbonate reservoir

architecture and heterogeneity, especially with regard to large-scale fluid flow from our reservoir

simulation work.

164

This task requires a setup phase which will be performed in conjunction with the creation

and validation of the integrated reservoir description. However, this work has more specific

goals than simply building the reservoir simulation model; considerable effort will go into the

validation of the petrophysical, fluid (PVT), and rock-fluid properties in order to establish a

benchmark case, as well as bounds (uncertainty ranges) on these data. In addition, well

performance data will be thoroughly reviewed for accuracy and appropriateness.

The history matching phase in this task will involve refining and adjusting data similar to

previous tasks, but in this work our sole focus will be to establish the most representative

numerical model for both the Appleton and Vocation Fields. Adjustments will undoubtedly be

made to all data types, but as a means to ensure appropriateness, these adjustments will be made

in consultation and collaboration with the geoscientists on the technical team. Our goal is to

obtain a reasonable match of the model and the field data, and to scale-up the small-scale

information (core, logs, etc.) in order to yield a representative reservoir simulation model. We

will use a black oil formulation for this work.


completed. Fluid data (Figures 181-183 and Tables 17-20), rock properties (Figures 184-185),

historical production (Table 21 and Figures 186-187), phase flowrates (Figures 188-189),

cumulative production (Figure 190), gas-oil ratio profile (Figure 191), watercut profile (Figure

192), oil production rate history match (Figure 193), water production rate history match (Figure

194), gas production history match (Figure 195) and water production rate history match per

well (Figures 196-200) were used in the simulation model for Appleton Field. The results of the

simulation for Appleton Field are illustrated in Figures 201-205. Fluid data (Figures 206-207 and

165

Fig. 181 — Fluid Report Well 3854, Appleton Oil Field.12

Fig. 182 — Fluid Report Well 3986, Appleton Oil Field.12

Fig. 183 – Phase Envelope, Appleton Oil Field.

166

Table 17 — Pseudocomponent Grouping, Appleton Field.

Pseudocomponent ComponentsGroup 1 H2S Group 2 C1 + N2 Group 3 C2 + CO2 Group 4 C3+C4+C5 Group 5 C6 + C7

Table 18 — Pseudocomponent Properties, Appleton Field.

Component Molecular Weight

(dim-less)

Critical Temperature

(deg R)

Critical Pressure, (psia)

Critical z-Factor

(dim-less)

Acentric Factor

(dim-less) Group 1 34.07 672.48 1296.18 0.2820 0.0642 Group 2 16.42 339.39 662.20 0.2847 0.0089 Group 3 35.11 549.29 839.63 0.2931 0.0927 Group 4 56.71 744.35 555.77 0.2790 0.1232 Group 5 179.62 1216.73 289.19 0.2524 0.3783

Table 19 — Pseudocomponent Properties, Appleton Field (continued).

Component

Ωa

(dim-less)Ωb

(dim-less)Vs

(dim-less)Group 1 0.4898 0.0749 -0.000642Group 2 1.0288 0.1109 -0.000887Group 3 0.9591 0.1235 -0.000501Group 4 0.6951 0.0965 -0.000362Group 5 0.6951 0.0717 0.000663

Table 20 — Binary Interaction Coefficients, Appleton Field.

Group 1 Group 2 Group 3 Group 4 Group 5 Group 1 0.0 - - - - Group 2 0.0540 0.0 - - - Group 3 0.0622 0.0369 0.0 - - Group 4 0.0684 0.0011 0.0332 0.0 - Group 5 0.0684 0.016 0.0044 0.0062 0.0

167

Fig. 184 — Oil-Water Relative Permeability Curves used in the Simulation Study.

Fig. 185 – Gas-Oil Relative Permeability Curves used in the Simulation Study.

168

Table 21 – Reported Cumulative Production per Well, Appleton Oil Field.

Well

Oil

Production(MSTB)

Water Production(MSTB)

Gas Production(MMSCF)

3854 405 1,246 850 3986 158 141 309

3986B 41 32 86 4633B 1,149 1,618 1,781 4835B 778 738 1,468 6247B 184 334 280

169

Fig. 186 — Oil Production as a Function of Well Location, Appleton Field.

Fig. 187 — Water Production as a Function of Well Location, Appleton Field.

170

Fig. 188 — Individual Phase Flowrates, Appleton Field (Cartesian Format).

Fig. 189 — Individual Phase Flowrates, Appleton Field (Semilog Format).

171

Fig. 190 — Cumulative Production Profiles, Appleton Field.

Fig. 191 — Gas-Oil Ratio Profile, Appleton Field.

172

Fig. 192 — Watercut Profile, Appleton Field.

173

Fig. 193 — Oil Production Rate History Match, Appleton Field.

Fig. 194 — Water Production Rate History Match, Appleton Field

174

Fig. 195 — Gas Production Rate History Match, Appleton Field.

Fig. 196 — Water Production History Match, Appleton Well 3854B.

175

Fig. 197 — Water Production History Match, Appleton Well 3986.


176



177

Fig. 201 - Initial Oil Saturation Profile as Loaded into VIP-CORE®

Initial oil saturation (So) (Fraction)

178

Fig. 202 – Simulated Unswept Area in the Appleton Oil Field Simulation Layer 1

179


180


181


182

Fig. 206 — Fluid Report Well 1599, Vocation Oil Field.13

.

Fig. 207 – Phase Envelope, Vocation Field.

Tables 22-25), rock properties (Figures 208-209), historical production (Table 26 and Figures

210-211), phase flowrates (Figures 212-213), cumulative production (Figure 214), gas-oil ratio

profile (Figure 215), watercut profile (Figure 216), oil production rate history match (Figure

217), water production rate history match (Figure 218), gas production rate history match

(Figure 219) and water production history match per well (Figures 220-229) were used in the

simulation for Vocation Field. The results of the simulation for the field are illustrated in Figures

230-232. The 3-D geologic model served as the framework for these simulations. The acquisition

of additional pressure data would improve the simulation models.

Work Planned for Year 3

Task 7—Geologic-Engineering Model. This task (Table 27) builds an integrated geologic

and engineering model(s) for reef and shoal reservoirs associated with petroleum traps in

Smackover fields represented by varying degrees of relief on pre-Mesozoic basement

paleohighs. The Appleton case study (low-relief) and the Vocation case study (high-relief) are

the basis for the model(s). The geologic model(s) is constructed utilizing the geological and

geophysical characterization data for the reef-shoal reservoir and structure at Appleton and

Vocation Fields. While these data will serve as the basis for the geologic-engineering model(s),

many types and scales of engineering data will be incorporated into the model(s) as well. In Task

6, the geologic model(s) for these fields was used as the underlying framework for flow

simulation of the Appleton and Vocation reservoirs. In this task, the reservoir simulation

model(s) from these fields is used to refine and adjust the geologic model(s) for Appleton and

Vocation Fields by integrating the results from the reservoir simulation modeling into the

geologic model(s). Geologic and geophysical data are critical for building our representative

geologic model(s) which will characterize, model and predict reservoir architecture,

heterogeneity and quality.

Brian Panetta

183

184

Table 22 — Pseudocomponent Grouping, Vocation Field.

Pseudocomponent ComponentsGroup 1 C1 + N2 Group 2 C2 + CO2 Group 3 C3 Group 4 C4 + C5 Group 5 C6 + C7

Table 23 — Pseudocomponent Properties, Vocation Field.

Component Molecular Weight

(dim-less)

Critical Temperature

(deg R)

Critical Pressure, (psia)

Critical z-Factor

(dim-less)

Acentric Factor

(dim-less) Group 1 17.64 327.89 644.28 0.2845 0.0166 Group 2 31.26 549.99 739.41 0.2878 0.1094 Group 3 44.10 665.97 615.75 0.2762 0.1524 Group 4 63.85 789.93 521.87 0.2751 0.2145 Group 5 160.13 1169.96 293.41 0.2629 0.4918

Table 24 — Pseudocomponent Properties, Vocation Field (continued).

Component Ωa

(dim-less)Ωb

(dim-less)Vs

(dim-less)Group 1 0.6951 0.0717 -0.1425 Group 2 0.4898 0.0749 -0.0981 Group 3 1.0288 0.1109 -0.0775 Group 4 0.9591 0.1235 -0.0477 Group 5 0.6951 0.0965 0.2561

Table 25 — Binary Interaction Coefficients, Vocation Oil Field.

Group 1 Group 2 Group 3 Group 4 Group 5 Group 1 0.0 - - - - Group 2 0.019519 0.0 - - - Group 3 0.013889 0.008559 0.0 - - Group 4 0.013889 0.008559 0.0 0.0 - Group 5 0.049655 0.017704 0.013889 0.0 0.0

185

Fig. 208 — Oil-Water Relative Permeability Curves used in the Simulation Study.

Fig. 209 – Gas-Oil Relative Permeability Curves used in the Simulation Study.

186

Table 26 – Reported Cumulative Production per Well, Vocation Oil Field.

Well

Oil

Production(MSTB)

Water Production(MSTB)

Gas Production(MMSCF)

1599 168 0 532 1830 733 332 1750 2851 388 1810 530 2935 165 817 284 3412 36 84 60 3739 529 163 1286

4225A 47 28 79 4225B 29 50 71 5779 102 50 226 11185 120 0.6 194

187

Fig. 210 — Oil Production as a Function of Well Location, Vocation Field.

Fig. 211 — Water Production as a Function of Well Location, Vocation Field.

188

Fig. 212 — Individual Phase Flowrates, Vocation Field (Cartesian Format).

Fig. 213 — Individual Phase Flowrates, Vocation Field (Semilog Format).

189

Fig. 214 — Cumulative Production Profiles, Vocation Field.

Fig. 215 — Gas-Oil Ratio Profile, Vocation Field.

190

Fig. 216 — Watercut Profile, Vocation Field.

Fig. 217 — Oil Production Rate History Match, Vocation Field.

191

Fig. 218 — Water Production Rate History Match, Vocation Field.

Fig. 219 — Gas Production Rate History Match, Vocation Field.

192

Fig. 220 — Water Production History Match, Vocation Well 1599.


193



194



195


Fig. 227 — Water Production History Match, Vocation Well 4225B.

196


Fig. 229 — Water Production History Match, Vocation Well 11185

197

Fig. 230— Initial Oil Saturation (Cross Section), Vocation Field.

198

Fig. 231 – Final Oil Saturation (Cross Section), Vocation Field.

Pssible infill drilling locations.

199

Fig. 232 — Depth to Reservoir Top, Vocation Field.

200

Table 27. Milestone ChartYear 3.

Tasks S O N D J F M A M J J A

Task 7—Geologic-Engineering Model x x x x x x Task 8—Testing Geologic-Engineering Model x x x x x Task 9—Applying Geologic-Engineering Model x x x x x Task 10—Technology Workshop x Task 11—Final Report x

xxxxx Work Planned

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However, the incorporation of petrophysical and engineering data will improve our

understanding of rock-fluid interactions, of subtle variations in reservoir architecture and

heterogeneity, and of flow units, barriers to flow, and reservoir-scale flow patterns. As the

integration of geoscience with engineering produces an improved reservoir simulation model to

assess and enhance existing field recovery operations, the integration of engineering with

geoscience yields an improved predictive geologic-engineering model. Coupling this geologic-

engineering model(s) with seismic data, we can evaluate the potential of a prospective carbonate

reservoir and structure for drilling. With the addition of well performance and production history

data from existing wells, we can design a plan for optimum development of the prospect. From

this work, we anticipate being able to create a single geologic-engineering model for reef and

shoal reservoirs associated with basement paleohighs of varying degrees of relief though we

realize that two models may be required—one for reef-shoal reservoirs associated with low-relief

paleohighs and one for reef-shoal reservoirs associated with high-relief paleohighs.

Task 8—Testing of Geologic-Engineering Model.--This task focuses on the use of the

geologic-engineering model(s) as a predictive methodology to evaluate the potential of a

prospective reef-shoal reservoir associated with a basement paleohigh to be identified for study

by Paramount. Seismic data from the prospective structure and reservoir will be integrated into

the model(s). The model(s) will then be used in the interpretation of the seismic data to improve

the detection, characterization and imaging of the reservoir and to improve the prediction of flow

in the potential reef-shoal reservoir. The knowledge gained from studying the Appleton and

Vocation reservoirs and structures will facilitate this seismic integration approach. As part of this

process, seismic forward modeling will be performed to determine whether reef-shoal lithofacies

are present on the crest, flanks, or both crest and flanks of this paleohigh. Seismic attributes will

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be studied to determine whether reef-shoal reservoir porosity is expected on the crest, flank, or

crest and flanks of this paleohigh. Based on the seismic forward modeling and seismic attribute

studies, a decision will be made as to whether to drill and where on the paleohigh to drill this

prospect. Although the drilling of this well and of any confirmation well will occur after the

conclusion of the project, the geologic-engineering model will be used in determining the

location for the confirmation well and in the design of the field development plan. This model(s)

also will be utilized to predict fluid flow in this prospective reservoir based on the integrated

geologic and engineering studies at Appleton and Vocation Fields. Landmark SeisWorks Family

and KINGDOM Suite software, including 2d/3d PAK, will be used in the interpretation of the

seismic data and attribute study. It is important that the geologic-engineering model(s) be

compatible with the KINGDOM Suite software because this is the software that is commonly

employed by independent operators in this region.

Task 9—Application of Geologic-Engineering Model.--This task will apply the geologic-

engineering model(s) to the Appleton reservoir and the Vocation reservoir to evaluate the

potential for new improved or enhanced oil recovery operations, such as a strategic infill drilling

program and/or a waterflood or enhanced oil recovery project in these fields. The evaluation

process will focus on the potential to improve field profitability, producibility and efficiency,

and ultimately, to sustain the life of these reservoirs. The geologic-engineering model(s) will be

applied with emphasis on reservoir management, and the recommendations resulting from these

efforts will be compared to those from the reservoir simulation modeling. The benefits of each

modeling approach (the geologic-engineering and the reservoir simulation) will be evaluated,

and final recommendations to improve profitability, producibility and efficiency at Appleton and

Vocation Fields will be made to the operators of these fields.

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Task 10—Technology Workshop.--The project results will be transferred to producers in

the Eastern Gulf Region through a technology transfer workshop to be held in Jackson,

Mississippi. The workshop will focus on the presentation of our geologic-engineering model(s)

and the application of the model(s) for the evaluation of prospective carbonate reservoirs.

RESULTS AND DISCUSSION

The Project Management Team and Project Technical Team are working closely together on

this project. This close coordination has resulted in a fully integrated research approach, and the

project has benefited greatly from this approach.

Geoscientific Reservoir Characterization


types and heterogeneity of the reef and shoal reservoirs at Appleton Field and Vocation Fields

have been characterized using geological and geophysical data.

The architecture and heterogeneities of reservoirs that are a product of a shallow marine

carbonate setting are very complex and a challenge technically to predict. Carbonate systems are

greatly influenced by biological and chemical processes in addition to physical processes of

deposition and compaction. Carbonate sedimentation rates are primarily a result of the

productivity of marine organisms in subtidal environments. In particular, reef-forming organisms

are a crucial component to the carbonate system because of their ability to modify the

surrounding environments. Reef growth is dependent upon many environmental factors, but one

crucial factor is sea-floor relief (paleotopography). In addition, the development of a reef

structure contributes to depositional topography. Further, the susceptibility of carbonates to

alteration by early to late diagenetic processes dramatically impacts reservoir heterogeneity.

Reservoir characterization and the quantification of heterogeneity, therefore, becomes a major

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task because of the physiochemical and biological origins of carbonates and because of the

masking of the depositional rock fabric and reservoir architecture due to dissolution,

dolomitization, and cementation. Further, the detection, imaging, and prediction of carbonate

reservoir heterogeneity and producibility is difficult because of an incomplete understanding of

the lithologic characteristics and fluid-rock dynamics that affect log response and geophysical

attributes.

Appleton Field

Based on the description of cores (11) and thin sections (379), 14 lithofacies had been

identified previously in the Smackover/Buckner at Appleton Field. Analysis of the vertical and

lateral distributions of these lithofacies indicates that these lithofacies were deposited in one or

more of eight depositional environments: 1) subtidal, 2) reef flank, 3) reef crest, 4) shoal flank,

5) shoal crest, 6) lagoon, 7) tidal flat, and 8) sabkha in a transition from a catch-up carbonate

system to a keep-up carbonate system. These paleoenvironments have been assigned to four

Smackover/Buckner genetic depositional systems for three-dimensional stratigraphic modeling.

Each of these systems has been interpreted as being time-equivalent from that work, two

principal reservoir facies, reef and shoal were identified at Appleton Field.

Based on the description of cores and thin sections, three subfacies have been recognized in

the reef facies. These subfacies include thrombolitic layered, reticulate and dendroid. Each

represents a different and distinct microbial growth form which has inherent properties that

affect reservoir architecture, pore systems, and heterogeneity. The layered growth form is

characterized by a reservoir architecture that is characterized by lateral continuity and high

vertical heterogeneity. The reticulate form has a reservoir architecture that is characterized by

high vertical and lateral continuity. The dendroid form has a reservoir architecture that is

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characterized by high vertical and moderate lateral continuity and moderate heterogeneity. The

pore systems in each of these reservoir fabrics consist of shelter and enlarged pore types. The

enlargement of these primary pores is due to dissolution and dolomitization resulting in a vuggy

appearing pore system. Three subfacies have been recognized in the shoal facies. These

subfacies are the lagoon/subtidal, shoal flank, and shoal crest. The lagoon/subtidal subfacies has

a mud-supported architecture and therefore is not considered a reservoir. The shoal flank has a

grain-supported architecture but has considerable carbonate mud associated with it, and

therefore, has low to moderate reservoir capacity. The shoal crest has a grain-supported

architecture with minimal carbonate mud, and therefore, has the highest reservoir capacity of the

shoal subfacies. The pore systems of the shoal flank and shoal crest reservoir facies consist of

intergranular and enlarged pore types. The enlargement of the primary pores is due to dissolution

and dolomitization. Heterogeneity in the shoal reservoir is high due to the rapid lateral and

vertical changes in this depositional environment. Graphic logs were constructed for each of the

cores. The core data and well log signatures are integrated and calibrated on these graphic logs.

Appleton Field was discovered in 1983 with the drilling of the D.W. McMillan 2-14 well

(Permit #3854). The discovery well was drilled off the crest of a composite paleotopographic

structure, based on 2-D seismic and well data. The well penetrated Paleozoic basement rock at a

depth of 12,786 feet. The petroleum trap at Appleton was interpreted to be a simple anticline

associated with a northwest-southeast trending basement paleohigh. After further drilling in the

field, the Appleton structure was interpreted as an anticline consisting of two local paleohighs.

The D.W. McMillan 2-15 well (Permit #6247) was drilled in 1991. The drilling of this well

resulted in the structural interpretation being revised to consist of three local paleohighs. In

1995, 3-D seismic reflection data were obtained for the Appleton Field area. The interpretation

206

of these data indicated three local highs with the western paleohigh being separated into a

western and a central feature.

Based on the structural maps that we have prepared for the Appleton Field, we have

concluded that the Appleton structure is a low-relief, northwest-southeast trending ridge

comprised of local paleohighs. This interpretation is based on the construction of structure maps

on top of the basement, on top of the reef, and on top of the Smackover/Buckner from well log

data and 3-D seismic data.

The Smackover reservoir at Appleton Field has been influenced by antecedent

paleotopography. The Smackover thickness ranges from 177 feet in the McMillan 2-14 well

(Permit #3854) to 228 feet in the McMillan Trust 11-1 well (Permit #3986) in the field. As

observed from the cross sections based on well log data and on seismic data, the sabkha facies

thins over the composite paleohigh, while the reservoir lithofacies are thicker on the paleohigh.

Thickness maps of the sabkha facies, tidal flat facies, shoal complex, tidal flat/shoal complex,

and reef complex facies illustrate the changes in these lithofacies in the Appleton Field.

Vocation Field

Smackover deposition in the Vocation Field area is the product of the interplay of carbonate

deposition, paleotopography, and subsidence mainly of tectonic origin during a third order

eustatic sea level rise. Based on core descriptions, five shallow-marine environments in the

Smackover Formation were identified: microbial reef complex, shallow subtidal, shallow lagoon,

shoal complex, and tidal flat/sabkha. The last environment includes the Buckner Anhydrite

Member that in Vocation field is relatively thin with an average thickness of 20 to 30 feet. These

subenvironments define an overall aggradational and finally progradational shallowing upward

cycle developed in a restricted evaporate-carbonate setting.

207

The microbial reef complex facies is present in the lower part of the Smackover Formation.

It is very heterogeneous and consists of bafflestone (thrombolitic reticulate), bindstone

(thrombolitic layered) and oncoidal crusts, interbedded with dolomudstone/dolowackestone

layers. Stylolitic laminae are common. Allochems are bioclasts mainly of algae and bivalve

fragments, oncoids, peloidal clots, intraclasts, and ooids. The amount and types of pores are

highly variable, including primary shelter, interparticle and intraparticle porosity and secondary

solution enlarged/vuggy, moldic, and fracture pores. In some cases, anhydrite partially occludes

vuggy pores and fractures. Significant development of microbial buildups are located on the

northeastern side (leeward side) of the basement structure, while in the western side of the

structure (windward side) grainy sediments were deposited, but their original texture is difficult

to identify due to intense dolomitization.

The shallow subtidal facies is also present in the lower part of the Smackover succession but

in off-structure locations. It is composed of dark brown skeletal dolowackestone with subtle

plane parallel to wavy lamination. Some intervals display patchy textures indicative of microbial

influence. Allochems are mainly peloids, and sporadic ooids and skeletal debris, such as

echinoderm spines and bivalve fragments. Stylolites and horsetail lamination enriched in

authigenic pyrite are very common. Scarce and small anhydrite nodules are also present.

The shallow lagoon facies represents deposits accumulated behind a reef and/or shoal

barrier. It is composed of light brown dolowackestone to dolopackstone interbedded with darker

dolomudstone and argillaceous beds. Microbial buildups of up to 10-feet thick and fine-grained

grainstone are sporadically present. Allochems are scarce and consist mainly of isolated peloids,

ooids, oncoids, and intraclasts. Localized wavy lamination showing effects of bioturbation is

common in this facies.

208

Deposited in the upper parts of the Smackover Formation, the shoal complex facies

comprises most of the producing intervals in the field. It consists of carbonate sand bars

consisting of ooid/oncoidal dolograinstone/dolopackstone in thick, sometimes cross-stratified

layers, interbedded with thinner dolopackstone/dolowackestone beds. Allochems are mainly

ooids and oncoids though intraclasts and peloids are also common in the shoal flanks. Anhydrite

in the form of nodules or as cement is an important constituent of this facies. Porosity is

moderate to high and consists of primary interparticle and secondary moldic, intraparticle, and

vuggy pores, and microfractures. Some intervals display low porosity (<5%) values due to

cementation and compaction processes.

The shoal complex is the uppermost depositional facies of the Smackover Formation and

consists of laminated dolomudstone to dolowackestone interbedded with thick anhydrite layers

and microbial laminites (stromatolites). Stylolites and anhydrite nodules of varied sizes are very

common. Allochems are peloids with less common ooids and bioclasts. Porosity is commonly

low (< 6 %) due to the presence of dense anhydrite layers and the fine-grained texture of the

carbonate sediments, although in some cases the extensive dolomitization of this facies has

generated beds with high intercrystalline porosity. It consists of primary fenestral and secondary

moldic and microfracture porosity. Sporadic beds with solution enlarged pores are also present.

Vocation Field was discovered in 1971 with the drilling of the B.C. Quimby 27-15 (Permit

#1599) well. The discovery well was drilled near the crest of a paleotopographic structure based

on 2-D seismic and well log data. The well penetrated Paleozoic basement rock at a depth of

14,209 feet.

The Vocation field structure has been interpreted as a high relief composite

paleotopographic feature of the updip basement ridge play. It lies on the western flank of the

209

Conecuh Ridge in the southeastern margin of the Manila Sub-basin. Its position is updip of the

subcrop limit of the Louann Salt and 10 miles northeast of the regional peripheral fault trend.

The trap in Vocation field is combined (structural-stratigraphic), as the result of the onlap of

reservoir facies against the basement paleohigh. The structure at Vocation field is a composite

feature formed by Paleozoic granitic basement highs with irregular relief and steep slopes on the

flanks. It consists of a main north-south trending basement feature with three local highs that

remained subaerially exposed until the end of Smackover deposition. To the northeast, a smaller

feature with lower elevations has been successfully tested by three wells. This smaller structure

and the low area that separates it from the main feature were preferentially colonized by

microbial reefs, probably due to the presence of gentler depositional slopes formed by crystalline

igneous rocks. These surfaces provided the stable hardground necessary for the establishment

and growth of the microbial reef. The Vocation structure is characterized by embayed margins

and by high angle normal faulting that affected the Smackover Formation on the eastern and

northern flanks. Seismic data interpretation shows greater thicknesses of the Smackover section

on the downthrown blocks of the faults that cut the structure on the eastern flank indicating that

these faults were active during Smackover deposition.

The depositional sequence of the Smackover Formation varies dramatically in thickness in

the field from 0 ft (Well Permit 4786-B) in structurally elevated areas where the Smackover

pinches out against crystalline basement rocks, to 440 ft off-structure (Well Permit 3029). On-

structure, the Smackover section is the result of a shallowing-upward event in which four

shallow marine subenvironments were identified as follows: microbial reef complex, consisting

of bafflestone (reticulate thrombolites), bindstone (layered thrombolites) and oncoidal crusts,

interbedded with skeletal and peloidal dolopackstone to dolowackestone layers; shallow lagoon,

210

consisting of dolomudstone and dolowackestone to dolopackstone layers, with some bioturbated

levels and thin isolated microbial buildups that formed in a low energy environment behind the

reef and shoal complex; shoal complex, consisting of irregular and discontinuous sand bars made

up of ooid, oncoid and peloid dolograinstone and dolopackstone in thick, sometimes cross-

stratified layers of variable thickness interbedded with thinner dolopackstone to dolowackestone

levels and thin horizons rich in anhydrite nodules especially in the upper layers; and sabkha-tidal

flat, consisting of laminated peloidal dolomudstone to peloidal dolowackestone interbedded with

thick anhydrite layers and algal laminites (stromatolites). The Buckner Anhydrite Member,

which is relatively thin in the area (0 to 40 ft), is included in this interval. In general, this facies

is thicker close to the paleohigh crestal areas and progressively thinner toward the margins.

As in Appleton Field, the best potential reservoirs are associated with the microbial reef

facies mainly in the levels with reticulate thrombolite texture, and with the grainstone-packstone

shoal complex. The reservoir quality of these rocks is the result of the depositional fabric

combined with the effects of diagenetic processes, such as dolomitization and dissolution that

acted to increase the initial porosity and improved the connectivity of the pore network.

Significant thicknesses of microbial boundstone have been found only in the northeastern side of

the basement paleohigh but unfortunately below the oil/water contact. Instead, on the western

flank, fine-crystalline, highly dolomitized limestone was deposited.

Rock-Fluid Interactions

The study of rock-fluid interactions is near completion. Observation regarding the

diagenetic processes influencing pore system development and heterogeneity in these reef and

shoal reservoirs have been made.

211

Appleton Field

Based on initial petrographic studies, reservoir-grade porosity in the Smackover at Appleton

field occurs in microbial boundstone in the reef interval and in ooid, oncoidal, and peloidal

grainstone and packstone in the upper Smackover. Porosity in the boundstone is a mixture of

primary shelter porosity overprinted by secondary intercrystalline and vuggy porosity produced

by dolomitization and dissolution that is pervasive throughout the field. Porosity in the

grainstone and packstone is a mixture of primary interparticle and secondary grain moldic

porosity overprinted by secondary dolomite intercrystalline porosity.

Based on core analysis data, there is a distinct difference in reservoir quality between the

grainstone/packstone and boundstone reservoir intervals. Although the difference in reservoir

quality between these lithofacies is principally the result of depositional fabric, diagenesis acts to

enhance or impair the reservoir quality of these lithofacies. Porosity in the grainstone/packstone

reservoir interval in the McMillan 2-14 well (Permit #3854) ranges from 9.7 to 21.5% and

averages 14.8%. Permeability ranges from 1.1 to 618 md, having a mean of 63.5 md. Porosity in

the reef boundstone reservoir interval in the McMillan Trust 12-14 well (Permit #4633-B) ranges

from 11.9 to 25.0% and averages 18.1%. Permeability ranges from 14 to 1748 md, having a

mean of 252 md.

The higher producibility for the reef lithofacies is attributed to the higher permeability of

this lithofacies and to the nature of the pore system (pore-throat size distribution) rather than the

amount of porosity. Pore-throat size distribution is one of the important factors determining

permeability, because the smallest pore throats in cross-sectional areas are the bottlenecks that

determine the rate at which fluids pass through a rock.

212

Although both the reef and shoal lithofacies accumulated in diverse environments to

produce mesoscopic-scale heterogeneity, dolomitization and dissolution acted to reduce the

microscopic-scale heterogeneity in these carbonate rocks. The grainstone/packstone accumulated

in shoal environments and were later subjected to dolomitization and vadose dissolution. The

resulting moldic pore system, which includes primary interparticulate and secondary grain

moldic and dolomite intercrystalline porosities, is characterized by multisize pores that are

poorly connected by narrow pore throats. Pore size is dependent on the size of the carbonate

grain that was leached.

The boundstone accumulated in a reef environment and were later subjected to pervasive

dolomitization and nonfabric-selective, burial dissolution. The intercrystalline pore system,

which includes primary shelter and secondary dolomite intercrystalline and vuggy pores, is

characterized by moderate-size pores having uniform pore throats. The size of the pores is

dependent upon the original shelter pores, the dolomite crystal size, and the effects of late-stage

dissolution. The reef reservoir and its shelter and intercrystalline pore system, therefore, has

higher producibility potential compared to the shoal reservoir and its moldic pore system.

As confirmed from well-log analysis and well production history, hydrocarbon production in

Appleton field has occurred primarily from the boundstone of the Smackover reef interval, with

secondary contributions from the shoal grainstone and packstone of the upper Smackover. Total

reservoir thickness in the producing wells ranges from 20 ft (6 m) in the McMillan Trust 11-1

well (Permit #3986) to 82 ft (25 m) in the McMillan Trust 12-4 well (Permit #4633-B). With the

exception of the McMillan 2-14 well (permit #3854), where production has been primarily from

grainstone and packstone of the upper Smackover, the majority of the productive reservoir

occurs in boundstone.

213

The higher production from the reef interval is attributed to the better reservoir quality of the

boundstone and to the better continuity and connectivity of these carbonates. Whereas, the

grainstone/packstone interval is discontinuous, both vertically and laterally, the boundstone

interval appears to possess excellent vertical and lateral continuity.

In addition, although the microbial reef reservoir interval is more productive than the shoal

reservoir interval at Appleton Field, the dendroidal thrombolites have higher reservoir quality

than the layered thrombolites. Dendroidal thrombolites have a reservoir architecture

characterized by high lateral and vertical pore interconnectivity and permeability, while layered

thrombolites have good lateral but poorer vertical pore interconnectivity and permeability. Both

thrombolite architectures are characterized by pore systems comprised of shelter and enlarged

pores.

Vocation Field

The sequence of diagenetic events in the Smackover at Vocation Field occurred in the

eogenetic and mesogenetic stages. The eogenetic stage is the time interval between final

deposition and the burial, below the influence of surface-derived fluids of marine, brine, or

meteoric origin. The processes that occur within this stage are very active during relatively short

periods of time. Generally, the sediments and rocks of the eogenetic zone are mineralogically

unstable, or are in the process of stabilization, and therefore, porosity modification by

dissolution, cementation, and dolomitization is quickly accomplished. The mesogenetic stage

refers to the time interval in which sediments or rocks are buried below the influence of surficial

diagenetic processes until final exhumation in association with unconformities. Progressively

increased pressure and temperature and related rock-connate fluid interaction are the driving

214

mechanisms for burial diagenesis. In general, diagenetic processes that occur in the mesogenetic

zone operate at very slow rates but over long spans of geologic time.

Micritization is one of the earliest eogenetic events since it largely occurs near the sediment

/ water interface. It is produced by repeated boring activity of microorganisms such as algae and

fungi over the allochem surfaces and the subsequent infill of the borings with micrite generating

rims around the grains. This is a very common process in Smackover deposits especially in the

shoal facies at Vocation Field. Another early diagenetic event is the selective dissolution of

aragonite allochems generating moldic pores. It is produced by the action of meteoric waters

undersaturated with respect to calcium carbonate and affected mainly tidal and shoal deposits

because of their deposition very close to the sea water surface and probably reflecting a relative

sea-level fall. Isopachous rims of marine calcite cement (later dolomitized) coating allochemical

constituents have been found mainly in shoal facies and microbial reef facies in Vocation Field.

The vast majority of marine cementation occurs very near the sediment water interface where sea

water actively moves into the sediments. Precipitation of this early cement preserved primary

porosity from subsequent compaction. Mechanical compaction starts to affect carbonate

sediments under early burial conditions destroying mainly primary intergranular pores. This

process results in rotation and horizontal alignment of allochems and minor ductile grain

deformation expressed by embayed contacts among the grains. Compaction was more intense

where no early calcite cementation occurred. Dolomitization is one of the most significant

digenetic events that affects the Smackover Formation in the study area because it created new

intercrystalline pores that improved the connectivity of the pore network. Dolomitization is

ubiquitously present in the entire Smackover interval in Vocation Field. It is expressed by

neomorphism of calcareous allochems, matrix and cements into dolomite. This process also

215

includes precipitation of dolomite cement. Gypsum and/or anhydrite precipitation also

accompanied this process filling intergranular, vuggy and moldic pores, and as replacive nodules

principally in the upper part of the Smackover Formation. Normally the size of the crystals is

relative to the size of the grain being replaced. In some cases, penetrative dolomitization was

able to obscure the primary texture preventing a reliable identification of the original rock.

Rocks that experienced intense dolomitization display a sucrosic texture sometimes with high

intercrystalline porosity.

Once carbonate sediment has been mechanically compacted, continued burial increases the

chemical potential that eventually leads to the dissolution of the grains in a mesogenetic process

known as pressure-solution. The result is the presence of abundant high amplitude stylolites, and

anastomosing wispy seams and laminae of insoluble residue, mainly in the finer grained facies of

the Smackover Formation. These features are impermeable barriers to fluid flow. Chemical

compaction in the Smackover Formation is believed to be a significant source for later porosity

occluding, subsurface cements. Fractures and microfractures are normally present in the

Smackover Formation, especially in the microbial reef facies. Although time of formation is

difficult to define, this event occurred after dolomitization and lithification since normally the

fractures cut dolomitized particles. The partial infill with dolomitic, calcitic and late stage

anhydritic cements may imply that they began to form shortly after burial. The causes of

fracturing can be a combination of compaction and local tectonic activity. In the Smackover

Formation, the dissolution predates oil migration, and therefore, it is possible that its origin may

be related to the presence of aggressive pore fluids enriched in CO2 and organic acids associated

with early phases of oil maturation. This process is the result of the decarboxilation (loss of -

COOOH group) of organic material during the oil maturation process. Various types of

216

cementing materials, including dolomitic, siliceous, calcitic, and anhydritic cements obliterated

all types of porosity after burial. Ferroan dolomite cement is characterized by large crystals

commonly with euhedral shapes and cloudy centers. This cement probably was precipitated

immediately after the non-selective dissolution event since it normally fills vugs and cavities

formed during this diagenetic episode. It often also fills moldic and intercrystalline pores. In

some cases, the presence of saddle or baroque dolomite crystals with their characteristic

undulose extinction indicates that dolomitization occurred under deep burial conditions. Saddle

dolomite is commonly associated with hydrocarbons, and thus, implies late diagenetic formation

by sulfate reduction processes. Siliceous cement is present in very small amounts in the form of

isolated euhedral crystals. The source material for this cement is derived from pressure-solution

processes affecting very fine authigenic quartz grains normally present in small amounts in

Smackover deposits. Calcite cement is present normally as large sparitic crystals that embed

crystals and allochems and fill the available pore space among them. Supersaturation in calcium

carbonate of the formation fluids as the result of pressure-solution and late stage dissolution

associated with hydrocarbon maturation may be responsible for the precipitation of the calcite

cement. The time of formation may be close to the time of oil migration. This cementation

process remains active during the precipitation of late stage anhydrite cement as evidenced by

the common presence of the intergrowth of these two types of cements. Anhydrite is another

important late stage cement. It is considered one of the last events as inferred from the

characteristic coarse, slightly corroded crystals sometimes with a poikilotopic character and

because the anhydrite normally fills spaces that were partially occluded by other cements. The

source of material for this cement may be provided by former dissolution events of carbonate

rocks rich in sulfates due to pressure-solution and organic acid activity. Authors have suggested

217

that this anhydrite is probably precipitated from ion-charged solutions migrating updip from the

underlying Louann Salt.

Correlation between the depositional facies analysis of well cores and the petrophysical

properties of these rocks leads to the conclusion that despite diagenesis, the depositional fabric

defines the best reservoirs. In Vocation Field, the shoal complex and the microbial reef facies

display the best porosity and permeability properties. Within the tidal flats and especially in the

shallow lagoon environments, the deposition of isolated microbialite buildups and thin

packstone-grainstone levels also have reservoir potential. Nonetheless, diagenesis can, in some

cases, significantly affect and modify the distribution of reservoir grade rocks. Well Permit 2851

is an example of how penetrative dolomitization was able to generate reservoir grade intervals in

tidal flat deposits that actually produced oil in this well. The opposite case is Well Permit 2966

where precipitation of dolomite and anhydrite cements obliterated porosity in the ooid shoal

facies. Good correlation between porosity and permeability is the result of extensive

dolomitization, late stage dissolution, and fracturing that combined to connect isolated moldic

and vuggy pores to produce an effective pore system.

The shoal complex reservoirs are dolomitized ooid-oncoidal grainstone and packstone with

primary intergranular porosity and secondary intercrystalline, moldic and vuggy pores. In this

lithofacies, dolomitization improved connectivity among moldic pores and also generated new

intercrystalline pores. Early marine cementation contributed in the preservation of primary

porosity, while anhydrite and dolomite cementation are the main processes that occluded pores

in the shoal facies. Total porosity is commonly between 4 and 15% with an average of 10% and

permeability varies between 3 and 160 md with an average of 66 md. The thickness of the

reservoir interval is normally between 20 and 40 feet, reaching 90 feet. The shoal facies is

218

widespread in the field, but probably the high-quality reservoir intervals are not connected along

the entire length of the field due to pinch-outs and facies changes that are common in this

depositional setting.

The potential reef reservoir intervals are characterized by reticulate and layered thrombolite

fabrics commonly with primary shelter and intergranular porosity and secondary moldic,

solution enlarged and fracture porosity. This potential reservoir is petrophysically heterogeneous

due to the characteristic patchy texture of these deposits, and the presence of impermeable

wackestone-mudstone levels and insoluble residual laminae. In this lithofacies, dolomitization,

the nonselective dissolution episode, and fracturing substantially improved the amount of

porosity and the connectivity of isolated shelter and vuggy pores. The normal thickness for the

microbial reef intervals is between 100 and 150 feet, approximating a thickness of 200 feet (Well

Permit #3739). Core and well-log analyses suggest that these thick sequences are limited

spatially to the northeastern part of the structure. Porosity ranges between 8 and 20% with an

average of 13%, while permeability is in the order of 30 and 410 md with an average of 175 md.

Unfortunately, in Vocation Field significant accumulations of these facies are normally located

below the oil-water contact.

The Smackover Formation at Vocation Field has undergone a long history of diagenetic

events that document a paragenetic sequence similar to the ones described by other authors for

nearby areas. Average values of porosity (10 % and 13 %, respectively) in Vocation Field for the

shoal and microbial reef facies, which are commonly buried at depths greater than 14,000 feet,

indicate that diagenesis has been critical for the preservation and generation of significant

amounts of pore space. The most important diagenetic event for the preservation and

improvement of the reservoir properties is dolomitization that not only generated new porosity

219

but improved the connectivity among the existing pore space. Dissolution (i.e. leaching of

aragonite allochems and the deep non-fabric selective event) and fracturing were also important

in the generation of secondary porosity. Diagenesis began soon after deposition and evolved

through time due to progressively deeper burial conditions modifying the primary depositional

texture of the rock. Despite all the diagenetic overprints, the depositional textures still define the

best reservoirs.

Petrophysical and Engineering Property Characterization

Petrophysical and engineering property characterization is essentially completed. Appleton

and Vocation Fields have experienced a substantial decline in oil production since their initial

discoveries.

Appleton Field

Analysis of the core and log data indicate that the reservoirs at Appleton Field have a

heterogeneous nature. Porosity and permeability data show a significant difference in reservoir

quality between the shoal and reef reservoirs, with the reef facies having better reservoir quality

compared to the shoal facies. There is poor correlation between the core and log porosity

measurements for these facies. The oil in place calculated for Appleton Field using well

performance analysis is an optimistic total. Flow capacity of the wells in the field shows a trend

of improving reservoir quality in a north and easterly direction, and recoverable oil from each

well is strongly correlated with its flow capacity. Structural factors do not appear to have a

strong influence on oil recovery at Appleton Field.

Vocation Field

Analysis of the core and log data indicate that the reservoirs at Vocation Field have a

heterogeneous nature. Porosity and permeability show a significant difference in reservoir

220

quality between the shoal and reef reservoirs, with the reef reservoir having better reservoir

quality compared to the shoal facies. There is reasonable correlation between the core and log

porosity measurements for these facies. The correlation between core permeability and core

porosity approximates a straight line representing a log linear model. This implies that the

relationship between permeability and porosity at any point in the reservoir is more controlled by

the location of the point structurally rather than in which lithofacies the point occurs. The

primary production mechanisms in Vocation Field are believed to be depletion drive

(fluid/rock/gas expansion) and water drive from an adjoining aquifer. The oil in place calculated

for the field using well performance analysis is 33.8 million STB. It appears that oil recovery is

not controlled by the flow capacity of a well, but rather is attributable to the proximity of a

particular well’s perforations to the oil-water contact.

3-D Geologic Modeling

The 3-D geologic modeling of the structures and reservoirs at Appleton and Vocation Fields

utilized the integrated database of geological, geophysical, and petrophysical information.

Appleton Field

The 3-D geologic (structure and stratigraphic) model for Appleton Field included advanced

carbonate reservoir characterization (structural, sequence and seismic stratigraphy, outcrop

analog, depositional lithofacies, diagenesis and pore systems studies), three-dimensional

geologic visualization modeling, seismic forward modeling, and porosity and permeability

distribution analysis (seismic attribute and three-dimensional stratigraphic studies). The structure

at Appleton Field is a low relief composite paleotopographic high. The well production

differences in the field are related to the heterogeneous nature of the reservoir. The quality of the

reef reservoir is greater than that of the shoal reservoir due to higher permeabilities and better

221

connected pore systems inherent to the depositional architecture and diagenetic fabric of the reef

facies. Another significant factor controlling reservoir productivity is related to the variation in

the size of individual reservoir compartments associated with the eastern and western

paleohighs. The greater production from the eastern paleohigh is a reflection of the greater relief

of the paleohigh, which places more reef reservoir above the oil – water contact. Production from

the western paleohigh is limited by the lower relief of the structure, which places much of the

reef reservoir below the oil – water contact. Thus, at Appleton Field, because the shoal and reef

facies are continuous over this low relief composite paleohigh, reservoir producibility is

principally controlled by reservoir quality, in combination, with structural relief.

Vocation Field

The 3-D geologic model for Vocation Field included advanced carbonate reservoir

characterization (structural, sequence and seismic stratigraphy, outcrop analog, depositional

lithofacies, diagenesis and pore systems studies), three-dimensional geologic visualization

modeling, and porosity and permeability distribution analyses. The structure at Vocation Field is

a high relief composite paleotopographic feature with multiple water levels. The well production

differences in the field are related to the variable relief of the individual paleohighs and

associated oil – water contact. The shoal and reef facies and resulting reservoir distribution is

directly related to the individual paleohighs. The reef facies, which has higher reservoir quality

than the shoal facies, is limited to the northern and eastern portions of the field. This distribution

in reef facies is believed to be attributed to the microbial buildups occurring only on the leeward

side of the Vocation composite feature. On the leeward side, the microbes could grow in a

restricted environment not affected by ocean currents and circulation patterns. Another major

factor controlling reservoir occurrence and producibility is related to the presence and variation

222

in the size of the individual reservoir compartments associated with the elevation of the

individual paleohighs. If the paleohigh remained above sea level during Smackover deposition,

no marine shoal or reef facies could be deposited. Thus, too high a relief precludes reservoir

occurrence. However, greater production from certain paleohighs is a reflection of their greater

relief, which places more of the shoal or reef facies above the oil – water contact. Thus, at

Vocation Field because of the discontinuity of the shoal and reef facies due to the high relief of

the composite paleotopographic high and because of the differential relief on the individual

paleohighs, reservoir producibility is principally controlled by the degree of structural relief, in

combination with reservoir quality.

3-D Reservoir Simulation

The 3-D geologic models have served as the framework for the 3-D reservoir simulation

models for Appleton and Vocation Fields.

Appleton Field

The Appleton Field 3-D geologic model formed the foundation for reservoir simulation. The

geologic model incorporated a much finer scale representation of the structure and petrophysical

properties of the reservoir than could be accommodated for reservoir simulation. The simulation

model was upscaled to contain 21,600 cells (30 x 30 x 24). The cells were approximately 330 ft.

x 260 ft. x 20 ft.

The history matching study was conducted by withdrawing the amount of oil known to be

produced from each well and observing the associated water and gas production. The field

appears to be in hydraulic communication with an aquifer because of the volumes of water

produced. The history match was achieved by placing the oil-water contact at a depth of -12,685

ft. and placing an aquifer under the field. Oil production matches very well, and water

223

production prior to 1990 is a reasonable match. There is difficulty explaining the high water

production in the field after 1990. The history match and simulation model predict 11.8 million

STB original oil in place. This prediction is significantly lower than the estimate resulting from

well performance analysis. The simulation results indicate there is oil remaining to be recovered

near the top of the structure.

Vocation Field

The Vocation Field 3-D geologic model formed the foundation for reservoir simulation. The

geologic model incorporated a much finer scale representation of the structure and petrophysical

properties of the reservoir than could be accommodated for reservoir simulation. The simulation

model was upscaled to contain 30,600 cells (30 x 30 x 34). The cells were approximately 300 ft.

x 300 ft. x 10 ft.

The history matching study was conducted by withdrawing the amount of oil known to be

produced from each well and observing the associated water and gas production. The history

match was achieved by placing the oil – water contact at a depth of -13,693 ft. and placing an

aquifer under the western portion of the field. There may, however, be an aquifer under the entire

field. The history match and simulation model predict 31.7 million STB original oil in place.

This prediction agrees favorably with the estimate resulting from well performance analysis.

Data Integration

All geological, geophysics, petrophysical and engineering data generated to date from this

study have been entered and integrated into digital databases for Appleton and Vocation Fields.

CONCLUSIONS



224












The principal research effort for Year 2 of the project has been reservoir description and

characterization. This effort has included four tasks: 1) geoscientific reservoir characterization,

2) the study of rock-fluid interactions, 3) petrophysical and engineering characterization and 4)

data integration.


types and heterogeneity of the reef and shoal reservoirs at Appleton and Vocation Fields have

been characterized using geological and geophysical data. All available whole cores have been

described and thin sections from these cores have been studied. Depositional facies were

determined from the core descriptions and well logs. The thin sections studied represent the

depositional facies identified. The core data and well log signatures have been integrated and

calibrated on graphic logs. The well log and seismic data have been tied through the generation

of synthetic seismograms. The well log, core, and seismic data have been entered into a digital

225

database. Structural maps on top of the basement, reef, and Smackover/Buckner have been

constructed. An isopach map of the Smackover interval has been prepared, and thickness maps

of the Smackover facies have been prepared. Cross sections have been constructed to illustrate

facies changes across these fields. Maps have been prepared using the 3-D seismic data that

Longleaf and Strago contributed to the project to illustrate the structural configuration of the

basement surface, the reef surface, and Buckner/Smackover surface. Seismic forward modeling

and attribute-based characterization has been completed for Appleton Field. Petrographic

analysis has been completed and a paragenetic sequence for the Smackover in these fields has

been prepared.

The study of rock-fluid interactions is near completion. Thin sections (379) have been

studied from 11 cores from Appleton Field to determine the impact of cementation, compaction,

dolomitization, dissolution and neomorphism has had on the reef and shoal reservoirs in this

field. Thin sections (237) have been studied from 11 cores from Vocation Field to determine the

paragenetic sequence for the reservoir lithologies in this field. An additional 73 thin sections

have been prepared for the shoal and reef lithofacies in Vocation Field to identify the diagenetic

processes that played a significant role in the development of the pore systems in the reservoirs

at Vocation Field. The petrographic analysis and pore system studies essentially have been

completed. A paragenetic sequence for the Smackover carbonates at Appleton and Vocation

Fields has been prepared. Pore systems studies continue.


Petrophysical and engineering property data have been gathered and tabulated for Appleton and

Vocation Fields. These data include oil, gas and water production, fluid property (PVT) analyses

and porosity and permeability information. Porosity and permeability characteristics of

226

Smackover facies have been analyzed for each well using porosity histograms, permeability

histograms and porosity versus depth plots. Log porosity versus core porosity and porosity

versus permeability cross plots for wells in the fields have been prepared.

Well performance studies through type curve and decline curve analyses have been

completed for the wells in Appleton and Vocation Fields, and the original oil in place and

recoverable oil remaining for the fields has been calculated.

3-D geologic modeling of the structure and reservoirs at Appleton and Vocation Fields has

been completed. The model represents an integration of geological, petrophysical and seismic

data.


completed. The 3-D geologic model served as the framework for these simulations. The

acquisition of additional pressure data would improve the simulation models.

Data integration is up to date, in that, geological, geophysical, petrophysical and engineering

data collected to date for Appleton and Vocation Fields have been compiled into a fieldwide

digital database for development of the geologic-engineering model for the reef and carbonate

shoal reservoirs for each of these fields.

A technology workshop on reservoir characterization and modeling at Appleton and

Vocation Fields was conducted to transfer the results of the project to the petroleum industry.

REFERENCES

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227

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